Gamma ray image logging tool sensor placement

ABSTRACT

A method of creating a well image log of a cased well is provided. A passive cased well image logging tool assembly including a logging tool body, a plurality of gamma ray radiation sensor assemblies and a spatial positioning device is moved through at least a portion of the wellbore. Corrected gamma ray radiation data is vertically sampled. Based on the sampled data, a well image log is prepared. A passive cased well image logging tool assembly for use in a cased well is also provided.

BACKGROUND

An oil and gas well is created by drilling a wellbore on a desiredsurface site that extends from the surface to a certain depth ordistance into the ground. The wellbore penetrates the underlying earthand various geologic units therein. With proper planning and placement,one or more of the geologic units penetrated by the wellbore willinclude commercial quantities of hydrocarbons such as oil and gas. Thewellbore can extend vertically, at an angle and/or horizontally throughthe earth. For various reasons, including rock and drillingheterogeneities, the actual direction of a wellbore tends to deviate atleast to some extent from the intended direction of the wellbore. Also,the diameter and roughness (or rugosity) of the resulting boreholetypically changes as the wellbore is drilled because of similar rock anddrilling heterogeneities.

As the wellbore is being drilled, a drilling fluid, also referred to asdrilling mud, is continuously circulated from the surface through thewellbore and back to the surface. The drilling fluid functions to removecuttings from the borehole, control formation pressure, and cool andlubricate the drill bit. After the wellbore is drilled to a certain ortarget depth, casing (typically metallic casing) is usually inserted andcemented in place in the now completed wellbore. The casing typicallyextends to the total depth of the wellbore. The casing isolates andseals off various geologic zones that have been penetrated by thewellbore and serves multiple other purposes. Cement material is usuallyinjected around the casing and allowed to harden into an annular sheatharound the casing. The cement sheath physically supports, positions andprotects the casing in the wellbore and bonds the casing to the walls ofthe wellbore such that the undesirable migration of fluids between zonesor formations penetrated by the wellbore is prevented.

After the wellbore is drilled to the desired depth and cased, the wellis ready for the final completion and production phases. Finalcompletion of the well includes the creation of one or more accessconduits (for example, perforations) that extend through the casing andcement sheath to provide communication between the wellbore and one ormore of the geologic units from which hydrocarbons are to be produced.The casing and cement sheath provide a solid support for the accessconduits. Once the well is completed, the gas and/or fluids, which mayinclude hydrocarbons and water, are produced or allowed to flow from thenow completed geologic unit(s) into the wellbore and then to the surfacewhere they are processed for future use.

Numerous important procedures are typically carried out on a well duringthe well drilling phase and before the well completion phase. One ofthese procedures involves gathering geologic and engineering dataregarding the size and configuration of the borehole and the nature andcharacteristics of the surrounding geologic units. The collection ofsuch data, typically referred to as well logging or formation logging,can be performed by one of several downhole methods within the uncasedwellbore, including mud logging, wireline logging with a wireline cable,or using the bit assembly for measurement-while-drilling (MWD) orlogging-while-drilling (LWD) techniques. Various specialized loggingtools have been developed for use in connection with each method. Theparticular method and type of tools utilized will depend on severalfactors, including the borehole inclination and condition, costs andtime, and the type of geologic units penetrated by the wellbore.

In one downhole logging method, a logging tool is attached to the end ofa wireline cable and lowered to the desired depth in the wellbore (forexample, to the bottom of the wellbore) and then pulled back to thesurface at a set rate or speed (the “logging speed”). Data is collectedas the tool is pulled back to the surface and transmitted through thecable to the surface. In lieu of the wireline cable, for example,another downhole tool can be used to lower the logging tool into thewellbore and pull the logging tool out of the wellbore. The data isusually collected in a spatially-corrected fashion to increase theamount of true signal over the background noise. In order to make iteasier to use, the data is typically also sampled at a particularsampling rate.

Well logging tools have been around for decades. For example, when welllogging first began in the early 1900's, only spontaneous or ionicpotential and resistivity data was recorded. Today, there are manydifferent types of logging tool configurations available. Examplesinclude spontaneous potential logging tools, resistivity/conductivitylogging tools, image logging tools, acoustic logging tools anddensity/neutron logging tools. Most of the available logging tools arelimited to use in an open-hole environment, although certain types ofresistivity/conductivity logging tools and density/neutron tools can beused in both an open hole and a cased hole environment. The type of datacollected and the manner in which it is collected varies from tool totool.

An example of a modern logging tool is an image logging tool. An imagelogging tool is used to produce “images” of the borehole wall and thesurrounding geologic units penetrated by the wellbore. For example, animage logging tool can be used to identify the dip and azimuth of thegeologic units around the wellbore, locate rock breakouts within theborehole, identify fractures in the surrounding geologic units anddetermine the composition of the surrounding geologic units. Based onthe data collected, a useful well image log can be created thatrepresents the surface of the surrounding geologic units in thewellbore.

There are many factors that can alter the quality of the data collectedand recorded by an image logging tool, including the logging speed, thesampling rate, the rate of turning or spiraling of the logging tool inthe hole, the borehole contact with the sensor assemblies, the proximityof the sensor assemblies to the rock surface, the borehole internaldiameter, the borehole shape or rugosity, the borehole inclination, theradial arrangement of the sensor assemblies, the number and orientationof the sensor assemblies, and the sensitivity of the sensor assemblies.For example, the logging speed, sampling rate and orientation at whichdata is collected can be particularly important factors. Based on thedip and azimuth of the wellbore and the surrounding rock, it may bedetermined, for example, that the final location to which the wellboreis drilled needs to be changed and that the current wellbore needs to bere-drilled, or even that an additional wellbore needs to be drilled froma different location on the site in order to effectively and efficientlypenetrate the most promising geologic unit(s).

Well logging tools, including image logging tools, can be classified inmany ways, including but not limited to active vs. passive, pad vs.non-pad, statistical vs. non-statistical, and centered vs. offset oreccentric. For example, an active well logging tool emits a signal (forexample, nuclear radiation, energy waves or high energy particles) intothe wellbore and the surrounding geologic units in order to induce areturn signal that can be received and recorded by the same tool forlater processing into useful data. A passive well logging tool, on theother hand, merely receives emitted signals that contain the usefulinformation from the geologic units penetrated by the wellbore. Apassive well logging tool does not emit a signal into the wellbore orgeologic units.

The types of image logging tools in use today include micro-resistivitylogging tools, acoustic logging tools, and optical logging tools. All ofthese tools are suitable for use in an open-hole environment. Amicro-resistivity image tool is an active, non-statistical image loggingtool that measures the conductivity/resistivity of rock minerals,fluids, gases and other materials in a geologic unit. An acoustic imagelogging tool is an active, non-statistical image logging tool that usessonic waves that reflect off rock, fluid and other material surfaces. Anoptical image logging tool is an active, non-statistical image loggingtool that uses cameras to image the rock, fluid and other materialsurfaces. Micro-resistivity image logging tools are the most common andwidespread image logging tool in use today. All the major loggingvendors have at least one micro-resistivity imager in their portfolio.

A micro-resistivity image logging tool uses a signal transmitter to emita measured amount of electrical current through the borehole wall intothe geologic units surrounding the wellbore. Multiple signaltransmitters positioned around the tool to cover the entire areasurrounding the wellbore are typically used. The current emitted by eachsignal transmitter is altered by the conductivity/resistivity of therock minerals, fluids, gases and other materials that are adjacent tothe wellbore. The altered current is then received by a correspondingreturn signal sensor assembly attached to the logging tool. For example,the signal transmitters and return signal sensor assemblies can beplaced in pads that are forced against the rock wall by extendableoffset arms.

The time and distance interval between the emission of the current byeach signal transmitter and the receipt of the altered current by thecorresponding return signal sensor assembly together with the propertiesof the return signals such as their amplitudes and/or phases can be usedto determine the conductivity/resistivity of the materials in thegeologic units, that is, the ability of the materials to resistelectrical currents. The resulting formation micro-resistivity can berecorded, for example, as a function of the tool's depth or position inthe wellbore. This data is then later processed to create amicro-resistivity well image log showing different properties of thegeologic units surrounding the wellbore.

For example, the recorded resistivity of the rock and other materials inthe geologic units can be used to determine the nature of the rock andother materials. For example, the resistivity of shale is different thanthe resistivity of sand, and hydrocarbons and water will also impact thesignal and resulting data. The resistivity data can be very valuable inthe search for hydrocarbons and can dictate how the drilling and/orcompletion programs move forward.

A very important component of any image logging tool is the spatialcontrol of where the transmitters and signals are oriented in xyz spacerelative to the wellbore and the Earth. As used herein and in theappended claims, the “Earth” means the planet Earth. Over the lastseveral decades, tremendous advances have been made in this area withthe use of gyroscopes mounted inside the logging tool. Gyroscopes allowthe data to be corrected in xyz space relative to the wellbore and theEarth to greatly improve the data quality. The corrected data allows animage of the wellbore and the surrounding geologic units to be producedthat can be “unwrapped” to create a two dimensional or three dimensionalview of the inside of the wellbore. Such a well image log can provideinformation regarding, for example, the formation lithology, the natureof the bedding, the content of fluid in the formation, and the dip andazimuth of the surrounding rock. The ability to view processed data intwo-dimensional or three-dimensional space reduces the impact of poordata collection or processing errors due to faulty receivers, holewashouts, excessive tool spinning, insufficient receivers, poor samplingor high logging speeds. Thus, the quality of the final well image log issignificantly enhanced.

The ultimate goal of any image logging tool is to get an accuraterepresentation of characteristics of the geologic units surrounding thewellbore. One measure of the quality of the representation that can beobtained is the signal-to-noise ratio (the “S/N ratio”) associated withuse of the tool. Both the rock being penetrated and the logging toolused to record the data create noise, most of which is random and cannotbe easily eliminated. Reducing the noise and maximizing the signalstrength associated with any well logging tool is a primary objective inthe design and use of the tool. Maximizing the S/N ratio of an imagelogging tool will also improve the final product.

The S/N ratio associated with an image logging tool can be increased,for example, by decreasing the logging speed, using an eccentric, offsetor off-center arrangement of transmitter/sensor assembly pads, movingthe transmitter/sensor assembly pads closer to the wellbore wall,increasing the number of signal transmitters and corresponding signalsensor assemblies attached to the logging tool, acquiring data in moreaccurate three-dimensional xyz space, and then later processing the databetter in three-dimensional xyz space.

Due to the low S/N ratio associated with cased wellbores,micro-resistivity, acoustic and optical image logging tools aretypically only effective in an open-hole (non-cased) wellbore. Forexample, when a metal casing has been cemented in the wellbore, themetal in the casing interferes with the electrical, acoustic or opticalsignals being sent and received by the tool. The highly conductivenature of the metal casing creates “noise” that can overwhelm both thetool and the rock signal to and from the tool. A solid casing of anytype can make optical image logging tools worthless in looking atgeologic or engineering features in the surrounding formation. Forexample, solid plastic and composite casings are opaque in nature whichcan negatively impact the performance of optical image logging tools.Optical image logging tools are also negatively impacted by opaque orotherwise dirty drilling fluids, even in open holes.

Drilling rigs are very expensive to own, rent and operate. When a wellis being drilled or a drilling rig is otherwise in place, time is money.As a result, a great deal of effort is made to keep the drilling andcompletion process moving forward in a timely and cost-effectivefashion. However, many problems can come up that slow the process andcost the operator time and money. For example, getting a logging toolstuck in an open wellbore before casing has been run can be very timeconsuming and otherwise counterproductive. For example, logging toolsare often “fished out” of the wellbore by specialized subcontractors whoare brought out to the well site on a rush basis. Fishing a stucklogging tool out of the wellbore can take several days of rig andsubcontractor time to accomplish. A stuck logging tool of the type thatcontains an active radioactive source can activate regulatoryrequirements that the well be abandoned and filled with red cement (thered cement warns subsequent well drillers to stay away from the buriedactive radioactive source).

Depending upon the regulatory environment associated with the well, mostcompleted oil and gas wells are ultimately cased (typically with a metalcasing). As a result, electrical, acoustic and optic-based image loggingtools are only useful before the casing is installed.

The nature of an open-hole environment can also negatively impact theperformance of an image logging tool. For example, excessive mud-cakebuildup on the borehole wall can interfere with the signals beingtransmitted and received by an image logging tool. For example, apermeable rock zone that absorbs drilling fluid may result in a thickermud-cake buildup than an adjacent low permeability zone. Also, thenature of the drilling fluid in the wellbore of an uncased hole caninterfere with the signals being transmitted and received by an imagelogging tool. For example, highly resistive or conductive drilling mud,including commonly used oil-based muds, can be problematic formicro-resistivity image logging tools. Logging in an oil-based mud holewith a micro-resistivity image logging tool can require more complexdata collection and processing.

Also, due to the fact that micro-resistivity, acoustic and optical imagewell logging tools can generally only be used to evaluate the geology inunprotected open-hole environments, the tools are typically designed tobe pulled out of the hole by a wireline cable at a relatively highlogging speed, for example, at a logging speed of at least 1000 feet perhour (“FPH”), usually at about 1800 FPH, and sometimes up to 3600 FPH.When a well is being drilled, it is always important to get the wellcased and otherwise completed as soon as possible. This is due primarilyto the daily cost of having a drilling rig in place (even if thedrilling phase is complete, the drilling rig is still often used tocomplete the well). Also, in many wells, it is important to case thewellbore or one or more portions thereof quickly due to changing wellconditions. For example, in some cases, the wellbore wall is sloughingor the stability of the geologic units around the wellbore is otherwisedecreasing with time. In order to prevent the wellbore from collapsingor caving in, a well operator may decide that casing needs to be put inplace sooner as opposed to later.

Also, in an open-hole environment, the likelihood that changingpressures, changing borehole shapes and other conditions will cause animage logging tool to get stuck increases significantly at slowerlogging speeds. This problem is exacerbated by the outwardly biasingextendable arms and corresponding pads of modern micro-resistivity imagelogging tools which make it easier for such tools to get hung up on therock wall, for example, due to deviations (“doglegs”) in the inclinationof the borehole. As a result, wireline logging engineers operating inopen-hole environments are typically encouraged to use logging speeds ofat least 1000 FPH and preferably 1,800 FPH.

Unfortunately, for a given image logging tool in a given wellboreenvironment, the quality of the logging data decreases as the loggingspeed at which the tool is run increases. A faster logging speed means alower S/N ratio and less collected data. Less collected data means alower quality final image log. In order to accommodate faster loggingspeeds and maximize image quality, image logging tool designers andmanufacturers have increased the sophistication of the tools, includingthe number of pads and sensor assemblies on the tools, which allows ahigher sampling rate to be used. Although this addresses the problemwith low S/N ratios, it also significantly increases the cost of thetools. For example, a sophisticated micro-resistivity image logging toolcan cost over $500,000 today.

The high cost of sophisticated modern image logging tools also createsproblems in and of itself. For example, due to their high cost,micro-resistivity image logging tools are not widely available and canbe in limited local supply. As a result, such tools may not be availableto wireline logging engineers for use in a timely manner on a well. Forexample, additional planning and transportation costs may be incurred ifthe only available micro-resistivity image tool is located in anotherstate.

The increased sophistication and capability of modern micro-resistivityimage logging tools is not always needed. For example, in some cases,the well operator only needs or desires geologic unit dip and azimuthdata. If this is the case, modern micro-resistivity image logging toolsare used in a “dumbed-down” mode. In other words, the same expensivemicro-resistivity image logging tool is run in the same deterioratingdownhole environment and records the same data, but only part of thedata is processed and presented. This is very wasteful of the dataacquisition time and costs, particularly in view of the risk of placingsuch an expensive tool into poor wellbore conditions and thereby riskingthe tool being stuck.

SUMMARY

In one aspect, a method of creating a well image log of a cased well isdisclosed herein. The method comprises providing a passive cased wellimage logging tool assembly, and moving the logging tool assemblythrough at least a portion of the wellbore. The logging tool assemblyincludes an elongated logging tool body having a central longitudinalaxis, a plurality of gamma ray radiation sensors attached to the loggingtool body and spaced around the central longitudinal axis of the loggingtool body, each gamma ray radiation sensor being capable of continuouslycollecting gamma ray radiation data from one or more geologic unitssurrounding or adjacent to the wellbore as the logging tool assembly ismoved through the wellbore, and at least one spatial positioning deviceattached to the logging tool body that is capable of continuouslycollecting sensor position data reflecting the xyz spatial position ofthe gamma ray radiation sensors in the wellbore relative to the wellboreand the Earth as the logging tool assembly is moved through thewellbore. The method further comprises: as the logging tool assembly isbeing moved through the wellbore, using the gamma ray radiation sensorsto continuously collect gamma ray radiation data that is emitted by thegeologic unit(s); as the logging tool assembly is being moved throughthe wellbore, using the spatial positioning device to continuouslycollect sensor position data reflecting the xyz spatial position of thegamma ray radiation sensors within the wellbore relative to the wellboreand the Earth; using the collected sensor position data to correct thecollected gamma ray radiation data; sampling the corrected gamma rayradiation data; and preparing a well image log based on the sampledgamma ray radiation data. For example, the gamma ray radiation sensorscan be attached to and equally spaced around the central longitudinalaxis of the logging tool body.

In another aspect, a passive cased well image logging tool assembly foruse in a cased well is disclosed herein. The passive cased well imagelogging tool assembly comprises: an elongated logging tool body having acentral longitudinal axis; a plurality of gamma ray radiation sensorsattached to the logging tool body and spaced around the centrallongitudinal axis of the logging tool body, and at least one spatialpositioning device attached to the logging tool body. Each gamma rayradiation sensor is capable of continuously collecting gamma rayradiation data from one or more geologic units surrounding or adjacentto the wellbore as the logging tool assembly is moved through thewellbore. The spatial positioning device is capable of continuouslycollecting sensor position data reflecting the xyz spatial position ofthe gamma ray radiation sensors in the wellbore relative to the wellboreand the Earth as the logging tool assembly is moved through thewellbore. For example, the gamma ray radiation sensors can be attachedto the logging tool body and equally spaced around the centrallongitudinal axis of the logging tool body.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings included with this application illustrate certain aspectsof the embodiments described herein. However, the drawings should not beviewed as exclusive embodiments. The subject matter disclosed is capableof considerable modifications, alterations, combinations, andequivalents in form and function, as will occur to those skilled in theart with the benefit of this disclosure. Also, the various views in thedrawings are shown in different scales in order to illustrate theinvention and are not representative of the size of the actual loggingtool and components thereof that are disclosed herein. As used herein,terms of orientation such as vertical, horizontal, outwardly, inwardly,downwardly and upwardly with respect to the logging tool assemblydisclosed herein are to be construed in view of the manner in which thelogging tool assembly is positioned and oriented in the drawings.

FIG. 1A is a perspective view of one embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 1B is a cross-sectional view taken along the lines 1B-1B of FIG.1A.

FIG. 1C is an enlarged sectional view of one of the sensor assembliesillustrated by FIGS. 1A and 1B.

FIG. 2A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 2B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from eight of thetwelve sensor assemblies associated with the logging tool shown by FIG.2A.

FIG. 3A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 3B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from eight of thetwelve sensor assemblies associated with the logging tool shown by FIG.3A.

FIG. 4A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 4B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from eight of thetwelve sensor assemblies associated with the logging tool shown by FIG.4A.

FIG. 5A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 5B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from three of thesix sensor assemblies associated with the logging tool shown by FIG. 5A.

FIG. 6A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 6B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from six of thetwelve sensor assemblies associated with the logging tool shown by FIG.6A.

FIG. 7A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 7B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from twelve of thetwenty four sensor assemblies associated with the logging tool shown byFIG. 7A.

FIG. 8A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 8B is a plan view in the form of a diagram illustrating sensorassembly data recorded points and calculated points from twelve of thetwenty four sensor assemblies associated with the logging tool shown byFIG. 8A.

FIG. 9A is a perspective view of another embodiment of the passive casedwell image logging tool assembly disclosed herein.

FIG. 9B is a cross-sectional view taken along the lines 9B-9B of FIG.9A.

FIG. 10 illustrates the flow of wellbore fluid around and through thelogging tool assembly when a helical arrangement of sensor assembliesand sensors is utilized in association with the logging tool assemblydisclosed herein.

FIG. 11A is a side view illustrating an alternative embodiment of thesensor assemblies with respect to the logging tool body of the loggingtool assembly disclosed herein.

FIG. 11B is a cross-sectional view taken along the lines 11B-11B of FIG.11A.

FIG. 11C is an enlarged sectional view of one of the sensor assembliesillustrated by FIG. 11A.

FIG. 12A is a side view illustrating another alternative embodiment ofthe sensor assemblies with respect to the logging tool body of thelogging tool assembly disclosed herein.

FIG. 12B is a cross-sectional view taken along the lines 12B-12B of FIG.12A.

FIG. 12C is an enlarged sectional view of one of the sensor assembliesillustrated by FIG. 12A.

FIG. 13 is a schematic view illustrating the transmission of gamma rayradiation data from sensor assemblies of the logging tool assemblydisclosed herein to a recording device remote from the sensorassemblies.

FIG. 14A is a perspective view of the embodiment of the passive casedwell image logging tool assembly shown by FIGS. 4A and 4B in a wellbore.

FIG. 14B is a cross-sectional view taken along the lines 14B-14B of FIG.14A and further illustrating the focus areas of the sensors associatedwith the logging tool assembly disclosed herein and a “shadow zone”behind the sensors.

FIG. 15 is a schematic view illustrating use of all embodiments of thepassive cased well image logging tool assembly disclosed herein shown inassociation with one embodiment of the method disclosed herein.

FIG. 16 is an example of a well log that can be generated using themethod and passive cased well image logging tool assembly disclosedherein.

DETAILED DESCRIPTION

The present disclosure may be understood more readily by reference tothis detailed description. Numerous specific details are set forth inorder to provide a thorough understanding of the various embodimentsdescribed herein. However, it will be understood by those of ordinaryskill in the art that the embodiments described herein can be practicedwithout these specific details. In other instances, methods, proceduresand components have not been described in detail so as not to obscurethe related relevant feature being described. Also, the description isnot to be considered as limiting the scope of the embodiments describedherein.

In one aspect, this disclosure provides a method of creating a wellimage log of a cased well. In another aspect, this disclosure provides apassive cased well image logging tool assembly for use in a cased well.For example, the passive cased well image logging tool assemblydisclosed herein can be the passive cased well image logging toolassembly used in the method of creating a well image log of a cased welldisclosed herein.

In one embodiment, the method of creating a well image log of a casedwell disclosed herein comprises:

-   -   a. providing a passive cased well image logging tool assembly,        the logging tool assembly including:        -   an elongated logging tool body having a central longitudinal            axis;        -   a plurality of gamma ray radiation sensors attached to the            logging tool body and spaced around the central longitudinal            axis of the logging tool body, each gamma ray radiation            sensor being capable of continuously collecting gamma ray            radiation data from one or more geologic units surrounding            or adjacent to the wellbore as the logging tool assembly is            moved through the wellbore; and        -   at least one spatial positioning device attached to the            logging tool body that is capable of continuously collecting            sensor position data reflecting the xyz spatial position of            the gamma ray radiation sensors in the wellbore relative to            the wellbore and the Earth as the logging tool assembly is            moved through the wellbore;    -   b. moving the logging tool assembly through at least a portion        of the wellbore;    -   c. as the logging tool assembly is being moved through the        wellbore, using the gamma ray radiation sensors to continuously        collect gamma ray radiation data that is emitted by the geologic        unit(s);    -   d. as the logging tool assembly is being moved through the        wellbore, using the spatial positioning device to continuously        collect sensor position data reflecting the xyz spatial position        of the gamma ray radiation sensors within the wellbore relative        to the wellbore and the Earth;    -   e. using the collected sensor position data to correct the        collected gamma ray radiation data;    -   f. sampling the corrected gamma ray radiation data; and    -   g. preparing a well image log based on the sampled gamma ray        radiation data.

As used herein and in the appended claims, a “well” means a drilledwellbore and the geologic units surrounding or adjacent to the wellbore.The terms “wellbore” and “borehole” are used interchangeably and meanthe same thing. A “cased well” means a well in which the wellbore or asection thereof contains an annular casing (for example, an annularmetal casing). A “well image log” means a well log including an image ofall or a portion of a borehole wall and all or a portion of one or moregeologic units surrounding or adjacent to the wellbore. The well imagelog can be used to create a separate dipmeter log.

For example, the passive cased well image logging tool assembly used inthe method disclosed herein can be the passive cased well image loggingtool assembly disclosed herein and further described below. As usedherein and in the appended claims, a “passive” cased well image loggingtool assembly means a cased well image logging tool assembly thatcollects data from one or more geologic units surrounding or adjacent toa wellbore but does not emit a signal into the wellbore or the geologicunit(s). Unless stated otherwise, one element “attached to” anotherelement means the one element is directly or indirectly attached to, orincorporated into, the other element.

As used herein and in the appended claims, “collecting” data meansreceiving the data and transmitting the received data to anothercomponent. Receiving data, sensing data, and detecting data mean thesame thing and may be used interchangeably herein. Transmitting thereceived data to another component includes allowing or causing thereceived data to pass to another component. For example, the othercomponent can be a photomultiplier tube, a signal processing unit, amemory device for storing data, or a relay. The other component can belocated in the logging tool assembly itself or at another location (forexample, on the surface).

For example, “collecting” gamma ray radiation data means receiving gammaray radiation data naturally emitted from a geologic unit surrounding oradjacent to the wellbore, and transmitting the received data to anothercomponent. For example, gamma ray radiation data can be transmitted by agamma ray radiation sensor to a photomultiplier tube in which the datasignal is amplified. For example, gamma ray radiation data can betransmitted by a gamma ray radiation sensor to a relay in the loggingtool assembly and by the relay to a signal processing unit on thesurface.

For example, “collecting” sensor position data means receiving sensorposition data reflecting the xyz spatial position of the gamma rayradiation sensors in the wellbore relative to the wellbore and theEarth, and transmitting the received sensor position data to anothercomponent. For example, sensor position data can be transmitted by thespatial positioning device to a relay in the logging tool assembly andby the relay to a signal processing unit on the surface.

For example, the signal processing unit, wherever it is located, canrecord (for example, store) the data and/or process it for further use.For example, the signal processing unit can be or include a centralprocessing unit. The signal processing unit can be attached to thelogging tool assembly, attached to another downhole tool, located on thesurface of the well site associated with the well or located in a remotelocation.

As used herein and in the appended claims, “gamma ray radiation” meansgamma radiation arising from the radioactive decay of atomic nuclei.Gamma ray radiation includes gamma ray radiation that is naturallyemitted from one or more geologic units surrounding or adjacent to thewellbore. Gamma rays consist of high energy protons and have shortwavelengths, for example, less than one-tenth of a nanometer. Gamma rayradiation can be created by various sources including naturallyoccurring rock radioisotopes. Natural gamma rays can vary depending uponthe type of element from which they are emitted. For example, differenttypes of rock and other materials in a geologic unit emit differentamounts and different spectra of natural gamma ray radiation. Examplesof common naturally occurring rock radioisotopes in geologic unitspenetrated by wellbores include natural radioisotopes of uranium (U),potassium (K), and thorium (Th).

Gamma ray radiation is usually expressed in the oil and gas industry inAPI (American Petroleum Institute) units or in parts per million (ppm).For example, the total gamma ray radiation emission from a geologic unitor portion thereof from natural radioisotopes of uranium, potassium, andthorium is typically expressed in API units. For standard gamma raylogs, the individual gamma ray radiation emissions from thorium anduranium radioisotopes in the geologic unit or portion thereof aretypically expressed in parts per million, while the individual gamma rayradiation emission from potassium radioisotopes is typically expressedin terms of its bulk rock percentage. For example, the total gamma rayemission as well as the individual gamma ray emissions from thorium,uranium and potassium radioisotopes in a geologic unit or portionthereof can be collected by the logging tool assembly in accordance withthe method disclosed herein.

According to an Oilfield Glossary provided by Schlumberger at“www.glossary.oilfield.slb.com” at the time of filing this application,an API unit is defined as:

-   -   “The unit of radioactivity used for natural gamma ray logs. This        unit is based on an artificially radioactive concrete block at        the University of Houston, Tex., USA, that is defined to have a        radioactivity of 200 American Petroleum Institute (API) units.        This was chosen because it was considered to be twice the        radioactivity of a typical shale. The formation is the primary        standard for calibrating gamma ray logs. However, even when        properly calibrated, different gamma ray tools will not        necessarily have identical readings downhole because their        detectors can have different spectral sensitivities. They will        read the same only if the downhole formation contains the same        proportions of thorium, potassium and uranium as the Houston        standard. For example, logging while drilling (LWD) tools have        thicker housings than wireline tools, causing a different        spectral response to the three sources of radioactivity, and        therefore a different total gamma ray reading in some        formations. The nuclear well log calibration facility at the        University of Houston, known as the API pits, was opened in 1959        for the calibration of natural gamma ray and neutron logs. A        facility for calibrating natural gamma ray spectroscopy logs was        added later.”

In connection with the method disclosed herein, the relative changes inthe gamma ray values (in API units) with respect to gamma ray radiationemitted by a geologic unit are most important. The absolute values (inAPI units) of the gamma ray radiation emitted by the geologic units arenot as important.

As used herein and in the appended claims, “gamma ray radiation data”means data regarding one or more properties of gamma rays emitted fromone or more geologic unit(s) surrounding or adjacent to the wellbore. Inaccordance with the method disclosed herein, gamma ray radiation datacan be continuously collected by the gamma ray radiation sensors. Forexample, the gamma ray radiation data that is continuously collected bythe gamma ray radiation sensors is naturally emitted by the geologicunit(s).

Naturally occurring gamma ray radiation data can be analyzed tocharacterize, for example, rock or sediment in the geologic unit(s)surrounding or adjacent to the wellbore. Types of gamma ray radiationdata that can be collected by the logging tool assembly in accordancewith the method disclosed herein include the total natural gamma rayradiation emitted from a geologic unit or portion thereof, theindividual energy profiles corresponding to the types of radioisotopeelements (thorium, uranium and potassium) naturally emitting the gammaray radiation and the intensity or magnitude of the gamma ray radiation.For example, the distance between the point of emission of the naturalgamma ray radiation in the geologic unit and the gamma ray radiationsensor assembly of the logging tool assembly that receives the emissioncan be collected as well. For example, the absolute value of a change inthe intensity of the gamma ray radiation emitted from point to point ina geologic unit is as important as the magnitude of that change.

For example, shales usually emit more gamma rays than sands, sandstoneand carbonate rocks because radioactive potassium is a common componentin their clay content. The clay in shales also often contains a higheramount of uranium and thorium isotopes. For example, black shale rich inorganic compounds may emit far more gamma rays than clean sand becauseblack shale rich in organic compounds has a higher uranium content thansand. The following table shows typical gamma ray responses fordifferent types of rocks, as expressed in API units:

GAMMA RAY RESPONSE IN DIFFERENT ROCKS AND MINERALS (Expressed in APIunits) Type of Rock Typical Gamma Ray Values or Other Element (APIUnits) Limestone 10-30 Organic-rich shale  70-250 Sandstone 10-60 Salt 2-20 Shale 70-90As used herein and in the appended claims, the term “rock” includesrock, sediment, minerals and other elements in a geologic unit.

The gamma ray radiation data collected by the logging tool assembly inaccordance with the method disclosed herein can be corrected, correlatedand used to create useful well image logs. For example, the well imagelog prepared in accordance with the method disclosed herein can be aspectral gamma ray log. For example, the well image log prepared inaccordance with the method disclosed herein can be a spectral gamma raylog with uranium, potassium and/or thorium responses; i.e., composed ofuranium, potassium and/or thorium data. The ability to differentiatebetween the sources of the gamma ray radiation naturally emitted fromone or more geologic units allows spectral gamma ray logs to be created.For example, in a spectral gamma ray log, the total gamma ray responsecan be placed in the left column, and the separate responses frompotassium, uranium and thorium radioisotopes can be placed in the rightcolumn. For example, the orientation and intensity/magnitude of thegamma ray radiation can be used to determine the nature of the materialsin the geologic unit at each point in the unit from which the radiationis measured.

In addition to collecting gamma ray radiation data that is naturallyemitted from one or more geologic units surrounding or adjacent to thewellbore, the well logging tool assembly used in the method disclosedherein can collect gamma ray radiation data emitted by radioactivetracers that have been injected into the wellbore to provide a way toanalyze the placement and flow of fluids and materials in a geologicunit. For example, such gamma ray radiation data can be used todetermine where a frac job has gone or where production is coming fromin a subterranean formation.

As used herein and in the appended claims, a gamma ray radiation sensormeans a receiver, sensor, detector, or other device that is capable ofcollecting gamma ray radiation data that is emitted from a geologic unitsurrounding or adjacent to a wellbore. For example, one or more of thegamma ray radiation sensors of the logging tool assembly disclosedherein can be scintillation detectors or counters configured to measurethe number and energy of gamma rays.

As another example, one or more of the gamma ray radiation sensors ofthe logging tool body disclosed herein can include crystalsemiconductors formed of crystals having known properties that respondto gamma rays. For example, semiconductors formed of bismuth geraniumcrystals, gadolinium oxyorthosilicate crystals, cerium doped lutetiumoxyorthosilicate crystals, thallium impurity, “NaI(TI)” doped sodiumiodide crystals, and any combination thereof can be used. Crystalsemiconductors can have better intrinsic energy resolution thanscintillators with respect to gamma ray radiation. For example, thegamma ray radiation sensor assemblies can detect gamma rays from isotopetracers, including Scandium 46, Antimony 124, and Iridium 192.

For example, each of the gamma ray radiation sensors of the logging toolassembly disclosed herein can be a scintillation crystal. For example,each of the sensors can be part of a sensor assembly that includes ahousing and a photomultiplier tube associated with the sensor, whereinthe sensor is contained by the housing. For example, both the sensor andthe photomultiplier tube can be contained by the housing. For example,the photomultiplier tube can include a central longitudinal axis, afirst end, and a second end, wherein the sensor is attached to one endof the photomultiplier tube.

As used herein and in the appended claims, “sensor position data” meansdata that reflects the xyz spatial position of the gamma ray radiationsensor in the wellbore relative to the wellbore and the Earth as thelogging tool assembly is moved through the wellbore. A “spatialpositioning device” means a device that is capable of continuouslycollecting sensor position data. The spatial positioning devicefunctions to orient the gamma ray radiation data collected by the welllogging tool assembly into xyz space relative to the logging tool body.For example, the spatial positioning device can be used to correct thecollected gamma ray radiation data to xyz space relative to the wellboreand the Earth. For example, the spatial positioning device allows forproper spatial xyz placement of the collected data. The correctionprocess significantly improves the quality of the data provided by thelogging tool assembly as well as the quality of the subsequentlyprocessed data.

For example, the spatial positioning device can be a gyroscope. Ifdesired, two or more gyroscopes or other spatial positioning devices canbe attached to the logging tool body. Suitable gyroscopes for use inconnection with the logging tool assembly disclosed herein are availablefrom several vendors. One example of a suitable gyroscope device is soldby Scientific Drilling as a Gyro Measurement-While-Drilling (gyroMWD™)system. Another example of a suitable gyroscope device sold byScientific Drilling is a “Keeper Gyro™.”

In accordance with the method disclosed herein, various additionalcorrections can be made to the gamma ray radiation data to make it moreaccurate. For example, the method disclosed herein can further compriseprocessing the collected gamma ray radiation data to correct the data toaccount for the rugosity of the borehole, the thickness of the casingand optionally other parameters. For example, the rugosity of theborehole and the thickness of the casing and optionally one or moreadditional parameters can also be sensed by the well logging toolassembly disclosed herein or obtained from known data sources and usedby the well logging tool assembly, together with the collected gamma rayradiation data, to correct the gamma ray radiation data.

As used herein and in the appended claims, the “logging speed” at whichthe logging tool assembly is moved through the wellbore (or a portionthereof) means the rate at which the logging tool assembly (includingthe sensor assemblies and other components attached thereto) is movedthrough the wellbore (or a portion thereof) in terms of distance unitsper time units, for example, the number of feet per hour (“FPH”) thatthe logging tool is moved through the wellbore. Any logging speed usedin connection with open well logging tools, as known to those skilled inthe art with the benefit of this disclosure, can be used in associationwith the method disclosed therein. However, due to the fact that thewell is cased, the logging tool assembly used in connection with themethod disclosed herein can be moved through the wellbore (or a portionthereof) at a significantly slower logging speed than the logging speedstypically used in association with open hole environments.

For example, in accordance with the disclosed method, the logging toolassembly can be moved through at least a portion of the wellbore (or allof the wellbore) at a logging speed that is no greater than 750 FPH. Forexample, the logging tool assembly used in the method disclosed hereincan be moved through at least a portion of the wellbore (or all of thewellbore) at a logging speed in the range of from about 30 FPH to about600 FPH. For example, the logging tool assembly can be moved through atleast a portion of the wellbore (or all of the wellbore) at a loggingspeed in the range of from about 60 FPH to about 300 FPH. For example,the logging tool assembly can be moved through at least a portion of thewellbore (or all of the wellbore) at a logging speed in the range offrom about 120 FPH to about 180 FPH. For example, the logging toolassembly can be moved through at least a portion of the wellbore (or allof the wellbore) at a logging speed in the range of from about 160 FPHto about 170 FPH. For example, the logging tool assembly can be movedthrough at least a portion of the wellbore (or all of the wellbore) at alogging speed of about 165 FPH.

The fact that the wellbore is cased allows a slower logging speed to besafely used. For example, due in large part to the fact that a drillingrig is usually no longer required, the cost of creating the well imagelog in a cased hole environment is significantly lower than it would bein an open hole environment. The ability to run the tool at a slowerlogging speed means a higher sampling rate can be used which means thatmore gamma ray radiation data can be collected with a less complexlogging tool assembly (for example, as compared to modernmicro-resistivity, acoustic or optical image logging tool assemblies).

For example, the corrected gamma ray radiation data can be verticallysampled by the signal processing unit or another component. The signalprocessing unit or other component can be located in the logging toolassembly itself or at another location (for example, as or as part of acentral processing unit on the surface). The corrected gamma rayradiation data can be vertically sampled either as the method is carriedout or at another time.

As used herein and in the appended claims, “vertically sampling” thecorrected gamma ray radiation data means sampling the corrected gammaray radiation data along the longitudinal axis of the wellbore. Asunderstood by those skilled in the art, the longitudinal axis of thewellbore is not necessarily vertical—it can be horizontal or deviated atsome angle between vertical and horizontal, either away from the surfaceor toward the surface. Accordingly, as used in the term “verticalsampling,” the term “vertical” has no meaning other than along thelongitudinal axis of the wellbore. The dimension in which the verticalsampling is carried out can be distance, time or some other dimension.

For example, the dimension in which the vertical sampling is carried outcan be distance. As used herein and in the appended claims, the term“vertical distance sampling rate” means the rate at which samples of thedata are taken with respect to the vertical distance sampling interval.The “vertical distance sampling interval” means the distance that thelogging tool assembly moves through the wellbore for every sample thatis collected. For example, if S represents the continuous stream ofcorrected gamma ray radiation data transmitted by the spatialpositioning device, D represents the vertical distance sampling intervaland the vertical sampling is performed by measuring the value of the Sonce every D inches, then the vertical distance sampling rate, R(d), atwhich the vertical sampling of S is carried out can be represented bythe formula R(d)=1/D. Accordingly, if D is 1.75 inches, then R(d), is0.57. For example, D is no greater than six inches. For example, D is nogreater than 1.75 inches. For example, D is in the range of from about0.5 inches to 1.75 inches. For example, D can be in the range of fromabout 0.5 inches to about 1 inch.

For example, the dimension in which the vertical sampling is carried outcan be time. As used herein and in the appended claims, the term“vertical time sampling rate” means the rate at which samples of thedata are taken with respect to the vertical time sampling interval. The“vertical time sampling interval” means the time that the logging toolassembly moves through the wellbore for every sample that is collected.For example, if S represents the continuous stream of corrected gammaray radiation data transmitted by the spatial positioning device, Trepresents the vertical time sampling interval and the vertical samplingis performed by measuring the value of the S once every T second, thenthe vertical time sampling rate, T(d), at which the vertical sampling ofS is carried out can be represented by the formula T(d)=1/T.Accordingly, if T is 1.14 seconds, then the time vertical sampling rate,T(d), is 0.88. For example, T can be in the range of from about 0.25seconds to about 20.0 seconds. For example, T can be in the range offrom about 0.5 seconds to about 10.0 seconds. For example, T can be inthe range of from about 0.6 seconds to about 4.0 seconds. For example, Tcan be in the range of from about 0.90 seconds to about 1.30 seconds.For example, T can be about 1.14 seconds.

The specific vertical sampling rate(s) utilized in a given survey,whether expressed in terms of distance, time or some other dimension,will vary depending on the logging speed used, the rock type, thewellbore geometry, the required accuracy and other factors as known tothose skilled in the art with the benefit of this disclosure. Forexample, a statistically significant vertical sampling rate can be used.

The corrected gamma ray radiation data can also be horizontally sampled.Unlike vertical sampling, which collects data at points along orparallel to the longitudinal wellbore axis, horizontal sampling collectsdata at points outwardly and around with respect to the longitudinalwellbore axis (for example, perpendicularly or at some other angle withrespect to the longitudinal wellbore axis). As understood by thoseskilled in the art, the longitudinal axis of the wellbore is notnecessarily vertical—it can be horizontal or deviated at some anglebetween vertical and horizontal, either away from the surface or towardthe surface. Accordingly, as used in the term “horizontal sampling,” theterm “horizontal” has no meaning other than outwardly and around thelongitudinal axis of the wellbore.

Horizontal sampling can be a function of the number of sensor assembliesthat are arranged around the logging tool assembly and the wellborecasing wall. It will vary depending on the tool configuration and theinside diameter of the casing. It is also impacted by the sensorassembly window size and sensor assembly orientation. Both verticalsampling and horizontal sampling are improved by slowing the loggingtool down and increasing the number of sensor assemblies.

For example, the counting time associated with each gamma ray radiationsensor assembly attached to the logging tool body can vary depending onthe logging speed. As used herein and in the appended claims, the“counting time” associated with a gamma ray radiation sensor assemblymeans the number of sensing seconds that the sensor assembly uses tocreate a value. For example, a fast logging speed will cause the sensorassembly to move across a portion of emitting rock in less time than aslower logging speed on the same rock. As a result, the counting timeassociated with the sensor assembly will be higher with the slowerlogging speed.

As the counting time associated with a gamma ray radiation sensorassembly attached to the tool body increases, the number of gamma rayemissions collected by the sensor assembly also increases (assuminggamma rays are present at the time). As long as the counting time is thesame across the sampling interval (for example, the vertical distancesampling interval or vertical time sampling interval), then the numberof gamma ray emissions collected over that interval by the sensorassembly will be relatively equal. However, if the logging speed changesacross the sampling interval, then the number of gamma ray emissionscollected over that interval by the sensor assembly will change (due tothe changing counting time as opposed to changing gamma ray emissions).

For example, the counting time associated with each gamma ray radiationsensor assembly attached to the logging tool body is in the range fromabout 0.40 seconds per inch to about 60.00 seconds per inch. Forexample, the counting time associated with each gamma ray radiationsensor assembly attached to the logging tool body is in the range fromabout 0.50 seconds per inch to about 12.00 seconds per inch. Forexample, the counting time associated with each gamma ray radiationsensor assembly attached to the logging tool body is in the range fromabout 1.00 second per inch to about 4.00 seconds per inch. For example,at a logging speed of 165 FPH, the counting time associated with eachgamma ray radiation sensor assembly attached to the logging tool bodycan be about 1.83 seconds per inch.

The logging tool body has a shape that will allow the logging tool andcomponents attached thereto to fit within a wellbore. For example, thelogging tool body has a cylindrical cross-section that has a maximumdiameter that is less than the internal diameter of the casing. Forexample, when the logging tool body has a cylindrical cross-section, theouter diameter of the logging tool body can be 3.5 inches. The internaldiameter of the casing can be, for example, 4.8 inches.

For example, a sufficient number of gamma ray radiation sensors can beattached to the logging tool body and equally spaced around the centrallongitudinal axis of the logging tool body to allow gamma ray radiationdata to be collected at sufficient points around the circumference ofthe wellbore and an image log of an entire geologic unit surrounding thewellbore to be prepared. As will be understood by those skilled in theart with the benefit of this disclosure, the gamma ray radiation data atpoints between the sensors can be determined by interpolation of thedata received by the sensor assemblies. For example, the gamma rayradiation sensors can be altered, modified, or focused to increase theS/N ratio allowing for collection of more accurate spatially correctdata.

For example, the gamma ray radiation sensors can be attached to thelogging tool body and equally spaced around the central longitudinalaxis of the logging tool body. For example, at least four gamma rayradiation sensors and corresponding sensor assemblies can be attached tothe logging tool body and equally spaced around the central longitudinalaxis of the logging tool body. For example, at least six gamma rayradiation sensors and corresponding sensor assemblies can be attached tothe logging tool body and equally spaced around the central longitudinalaxis of the logging tool body. For example, at least eight gamma rayradiation sensors and corresponding sensor assemblies can be attached tothe logging tool body and equally spaced around the central longitudinalaxis of the logging tool body. The only limitation on the upper end ofthe number of gamma ray radiation sensors and corresponding sensorassemblies that can be attached to the logging tool body and equallyspaced around the central longitudinal axis of the logging tool body ispracticality. Multiple gamma ray radiation sensors attached to thelogging tool body and equally spaced around the central longitudinalaxis of the logging tool body increase the S/N ratio associated with thelogging tool assembly by improving both vertical and horizontalsampling.

For example, the logging tool body can further include an outer sheath.The gamma ray radiation sensors can be positioned within the outersheath. Positioning the gamma ray radiation sensors within the outersheath protects the sensors and helps prevent the logging tool assemblyfrom getting stuck in the well. Alternatively, the gamma ray radiationsensors can be attached to the outside surface of the outer sheath orpartially encased by the outer sheath.

For example, the logging tool assembly can further comprise a centralcore positioned along the central longitudinal axis of said logging toolbody between the central longitudinal axis of the logging tool body andthe sensors. For example, when the logging tool body further comprisesan outer sheath, the central core is positioned within the outer sheath.The central core includes a gamma ray shielding material. For example,the gamma ray shielding material can be formed of tungsten (W). Forexample, the entire central core can be completely formed of the gammaray shielding material. Alternatively, the central core can include aninner core wrapped with a central sheath formed of a gamma ray shieldingmaterial. For example, the inner core can be hollow or can be formed oflead or another energy absorbing material. For example, the central corecan include a lead inner core wrapped with a tungsten central sheath.The central core improves the performance of the logging tool assembly,for example, by increasing the signal-to-noise ratio associated with thetool assembly.

For example, the gamma ray radiation sensors can be linearly arrangedand spaced around the central longitudinal axis of the logging tool bodyin at least one row. As used herein and in the appended claims, statingthat the gamma ray radiation sensors are “linearly arranged around thecentral longitudinal axis of the logging tool body” means that the gammaray radiation sensors are arranged around the central longitudinal axisof the logging tool body in the same longitudinal positions with respectto the central longitudinal axis of the logging tool body. For example,the gamma ray radiation sensors can be linearly arranged and equallyspaced around the central longitudinal axis of the logging tool body inat least one row.

For example, the gamma ray radiation sensors can be linearly arrangedand equally spaced around the central longitudinal axis of the loggingtool body in two rows. For example, when two rows are utilized, thegamma ray radiation sensor assemblies in one of the rows can bevertically aligned to the sensors in the other row. As used herein andin the appended claims, stating that the sensors in one row are“vertically aligned” to the sensors in the other row means that thesensors in one row are in alignment with the sensors in the other rowwith respect to the central longitudinal axis of the logging tool body.For example, when two rows are utilized, the gamma ray radiation sensorassemblies in one of the rows can be vertically offset from the sensorsin the other row. As used herein and in the appended claims, statingthat the sensors in one row are “vertically offset” from the sensors inthe other row means that the sensors in one row are not in alignmentwith the sensors in the other row with respect to the centrallongitudinal axis of the logging tool body.

As another example, the gamma ray radiation sensors can be verticallystaggered and spaced around the central longitudinal axis of the loggingtool body in at least one row. For example, the gamma ray radiationsensors can be vertically staggered and equally spaced around thecentral longitudinal axis of the logging tool body in at least one row.For example, the gamma ray radiation sensors can be vertically staggeredand equally spaced around the central longitudinal axis of the loggingtool body in two rows. As used herein and in the appended claims, theterm “vertically staggered” means arranged in alternating longitudinalpositions around the central longitudinal axis of the logging tool bodywith respect to the central longitudinal axis of the logging tool body.

As another example, the gamma ray radiation sensors can be helicallyarranged and spaced around the central longitudinal axis of the loggingtool body in at least one row. As used herein and in the appendedclaims, “helically arranged” means arranged in a helix pattern. A helixpattern means a pattern forming a three-dimensional curve around thecentral longitudinal axis of the logging tool body, whereby the curve'sangle to a plane perpendicular to the central longitudinal axis isconstant. As another example, the gamma ray radiation sensors can behelically arranged and equally spaced around the central longitudinalaxis of the logging tool body in at least one row. For example, thegamma ray radiation sensors can be helically arranged and equally spacedaround the central longitudinal axis of the logging tool body in tworows.

For example, the logging tool assembly can include at least two sets ofgamma ray radiation sensors, wherein the gamma ray radiation sensors ineach set are attached to the logging tool body and equally spaced aroundthe central longitudinal axis of the logging tool body, and wherein thesets are spaced from each other along the central longitudinal axis ofthe logging tool body. For example, the logging tool assembly caninclude a first set and a second set of gamma ray radiation sensors,wherein the gamma ray radiation sensors can be helically arranged andequally spaced around the central longitudinal axis of the logging toolbody in at least two rows in each set. For example, the gamma rayradiation sensors can be helically arranged to form a two-rowright-handed helical arrangement around the central longitudinal axis ofthe logging tool body in each set. For example, the gamma ray radiationsensors in the first set can be helically arranged to form aright-handed helical arrangement around the central longitudinal axis ofthe logging tool body, and the gamma ray radiation sensors in the secondset can be helically arranged to form a left-handed helical arrangementaround the central longitudinal axis of the logging tool body.

For example, when the gamma ray radiation sensors are part of sensorassemblies and the sensor assemblies are linearly arranged and equallyspaced around the central longitudinal axis of the logging tool body inat least two rows, the sensor assemblies in each of the rows can bearranged such that the ends of the photomultiplier tubes to which saidsensors are attached in one row face the ends of said photomultipliertubes to which said sensors are attached in the other row. Such anarrangement can be used even when both the scintillation crystal and thephotomultiplier tube are contained by the housing.

For example, the well image logging tool assembly can be moved throughat least a portion of the wellbore (or all of the wellbore) inaccordance with the disclosed method by lowering or otherwise moving thetool assembly to the bottom of the well, or another point in thewellbore, and then pulling the tool assembly toward the surface of thewell. For example, the gamma ray radiation data can be collected fromgeologic unit(s) surrounding or adjacent to the wellbore as the toolassembly is pulled to the surface of the wellbore. For example, awireline cable can be attached to the top of the image logging toolassembly and used to lower the tool assembly into the cased well andpull the image logging tool assembly toward the surface of the well at apre-determined logging speed. As another example, the image logging toolassembly can be attached to a coiled tubing unit and moved through allor a portion of the cased hole. For example, in horizontal and otherangled wellbores, the logging tool assembly can be attached to adownhole tractor assembly which can help move the image logging toolassembly through the wellbore and get it to the total depth of thewellbore. As will be understood by those skilled in the art with thebenefit of this disclosure, other methods can also be used to move theimage logging tool assembly through the wellbore as well and get thetool to the total depth of the wellbore.

A well image log based on the collected gamma ray radiation data can beprepared by standard methods known to those skilled in the art with thebenefit of this disclosure. The gamma ray radiation data can berecorded, for example, as a function of the logging tool assembly'sdepth and position in the wellbore to create a gamma ray image logshowing different properties of the geologic units.

For example, the method disclosed herein can further comprise creating athree dimensional image of one or more geological units penetrated bythe wellbore based on the sampled gamma ray radiation data. The threedimensional image can be interpreted, for example, to determine the diporientation and bedding azimuth in the geologic unit and/or the natureof the materials in the unit.

For example, an event plane (such as a bed boundary, fracture or fault)crossing the borehole at an angle would generate events at each sensorassembly, and data reflecting these events can be collected at slightlydifferent depths in the wellbore. The relative offset, and the radialand azimuthal positions of each sensor assembly can then be used tocompute dip relative to the logging tool body position. Increasing themeasurement points provides the advantage of systematic redundancy,which allows the application of statistical error minimizationtechniques and higher S/N ratios.

For example, the cased well can be inactive or permanently abandoned. Asused herein and in the appended claims, an inactive well means a well inwhich production, injection, disposal or workover operations haveceased, but which has not been permanently abandoned. As used herein, aninactive well includes a well that has been shut in or temporarilyabandoned. For example, an inactive well can be a shut-in or temporarilyabandoned well. A permanently abandoned well means a well from which noproduction, injection, disposal or workover operations are expected tobe carried out in the future. For example, a permanently abandoned wellcan be a plugged well. For example, the cased well can be an inactive orpermanently abandoned well for which a well image log is not available.

Referring now to FIGS. 1-15 of the drawings, various embodiments of thepassive cased well image logging tool assembly for use in a cased welldisclosed and used in the method disclosed herein, generally designatedby the reference numeral 10, will be described. The passive cased wellimage logging tool assembly 10 comprises an elongated logging tool body12 having a central longitudinal axis 14, a plurality of gamma rayradiation sensors 16 attached to the logging tool body and equallyspaced around the central longitudinal axis of the logging tool body,and at least one spatial positioning device 18 attached to the loggingtool body.

Each sensor 16 is capable of continuously collecting gamma ray radiationdata from one or more geologic units surrounding or adjacent to awellbore as the logging tool assembly is moved through the wellbore. Forexample, each of the sensors 16 can be a scintillation crystal.

For example, each of the sensors 16 can be part of a sensor assembly 23that includes a housing 24 and a photomultiplier tube 26 associated withthe sensor, wherein the sensor is contained by the housing. For example,both the sensor 16 and the photomultiplier tube 26 can be contained bythe housing 24. For example, the housing 24 can be an elongated tubethat includes a central longitudinal axis 28. For example, thephotomultiplier tube 26 can include a central longitudinal axis 30, afirst end 32, and a second end 34, wherein the sensor 16 is attached toone end of the photomultiplier tube. The sensor assemblies 23 can beattached to the logging tool body 12 in a fixed, non-movable manner.

The housing 24 includes a window 36 therein that is positioned over thesensor 16 in the housing in order to allow gamma rays to effectivelytravel through the housing to reach the sensor. For example, the housing24 is attached to and extends along the central longitudinal axis 14 ofthe logging tool body 12. For example, the central longitudinal axis 28of the housing 24 is parallel to the central longitudinal axis 14 of thelogging tool body 12.

As best shown by FIG. 1C, the sensor is contained in a scintillatorsub-housing 37. As shown, the scintillator sub-housing 37 is anelongated tube that includes a central longitudinal axis 38. Forexample, as shown by FIG. 1C, the central longitudinal axis 38 of thescintillator sub-housing 37 is parallel to the central longitudinal axis14 of the logging tool body 12. For example, when the sensor 16 is agamma ray scintillation crystal, the sensor 16 fills the whole volume ofthe scintillator sub-housing 37. For example, when a gamma ray entersthe scintillator sub-housing 37, it bounces around throughout thecrystal causing the crystal to flash multiple times.

As shown, the photomultiplier tube 26 also extends along the centrallongitudinal axis 14 of the logging tool body 12. For example, thecentral longitudinal axis of 30 of the photomultiplier tube 26 isparallel to the central longitudinal axis 14 of the logging tool body 12and the central longitudinal axis 28 of the housing 24. For example, thesensor 16 is attached to the first end 32 of the photomultiplier tube26. A plurality of pins 39 are attached to the second end 34 of thephotomultiplier tube 30.

The spatial positioning device 18 is capable of continuously collectingsensor position data reflecting the xyz spatial position of the sensors16 in the wellbore relative to the Earth as the logging tool assembly 10is moved through the wellbore.

As shown by the drawings, the logging tool body 12 further includes anouter sheath 40 that includes an outside surface 41 a and an insidesurface 41 b. The sensor assemblies 23 are positioned within the outersheath 40. Positioning the sensor assemblies 23 within the outer sheath40 protects the sensor assemblies and helps prevent the logging toolassembly 10 from getting stuck in the well. The outer sheath can be usedto support the sensor assemblies 23. For example, the sensor assemblies23 can be attached to the inside surface 41 b of the outer sheath 40.Alternatively, for example, the sensor assemblies 23 can be attached tothe outside surface 41 a of the outer sheath 40 or partially encased bythe outer sheath 40. For example, the outer sheath 40 can be formed ofmetal, plastic or a composite material. For example, the outer sheath 40can be formed of aluminum.

For example, the logging tool assembly 10 can further comprise a centralcore 42 positioned within the outer sheath 40 along the centrallongitudinal axis 14 of the logging tool body 12 between the centrallongitudinal axis and the sensor assemblies 23. The central core 42includes a gamma ray shielding material. For example, the gamma rayshielding material can be formed of tungsten (W). For example, theentire central core 42 can be completely formed of the gamma rayshielding material, for example tungsten. Alternatively, the centralcore 42 can include an inner core 43 wrapped with a central sheath 44formed of a gamma ray shielding material. For example, the inner core 43can be hollow or can be formed of lead, a mixture of lead and tungsten,or another energy absorbing material. For example, the central sheath 44can have a thickness of about one inch. For example, the central core 42can include a lead inner core 43 wrapped with a tungsten central sheath44. The central core 42 improves the performance of the logging toolassembly 10, for example, by increasing the signal-to-noise ratioassociated with the tool assembly.

A signal processing unit 46 is also attached to the logging tool body12. As discussed above, alternatively, the signal processing unit can bepositioned on the surface or at some other location. An omnidirectionalgamma ray device 48 is also attached to the logging tool body. Theomnidirectional gamma ray device 48 functions to provide a base line foroffset normalization of gamma rays.

An attachment assembly 54 for allowing the logging tool assembly 10 tobe attached to the end of a cable wireline, coiled tubing, or tractorassembly for example, is positioned at the top 56 of the logging toolbody 12. For example, as known to those skilled in the art, theattachment assembly 54 can have a structure that allows the end of awireline cable to be attached thereto.

Although not shown by the drawings, the logging tool assembly 10 alsoincludes a number of other components including one or more circuits andsystems (not shown) necessary to allow the sensor assemblies tocommunicate with the signal processing unit (for example, to allow thesensor assemblies to transmit the data they collect and their positionrelative to the tool body to the signal processing unit), and tootherwise operate the tool as desired. For example, a standardcentralizer can be used to center the tool assembly 10 in the borehole.

For example, the arrangement in which the sensor assemblies 23 areattached to the logging tool body 12 and the number of sensor assembliesthat are used can vary. Most of the embodiments shown by the drawingsinclude six sensor assemblies 23 in each row. However, the number ofsensor assemblies 23 in each row can be decreased or increased. Forexample, each row can include four sensor assemblies 23.

Referring now specifically to FIGS. 1A and 1B, one embodiment of thepassive cased well image logging tool assembly 10 will be described. Inthis embodiment, six sensor assemblies 23 and corresponding sensors 16are linearly arranged and equally spaced around the central longitudinalaxis 14 of the logging tool body 12 in a plane 58 perpendicularlyextending from the central longitudinal axis of the logging tool bodyand in a row 59. The sensor assemblies 23 are directly attached to thelogging tool body 12.

Referring now specifically to FIG. 2A, another embodiment of the passivecased well image logging tool assembly 10 will be described. In thisembodiment, six sensor assemblies 23 and corresponding sensors 16 arelinearly arranged and equally spaced around the central longitudinalaxis 14 of the logging tool body 12 in a plane 60 a perpendicularlyextending from the central longitudinal axis of the logging tool bodyand in a first row 62. In addition, six sensor assemblies 23 andcorresponding sensors 16 are linearly arranged and equally spaced aroundthe central longitudinal axis 14 of the logging tool body 12 in a plane60 b perpendicularly extending from the central longitudinal axis of thelogging tool body and in a second row 64. The sensor assemblies 23 aredirectly attached to the logging tool body 12. The sensor assemblies 23and corresponding sensors 16 in the first row 62 are vertically alignedto the sensor assemblies 23 and corresponding sensors 16 in the secondrow 64.

As shown by FIG. 2A, the sensor assemblies 23 in each of the rows 62 and64 are arranged such that the first ends 32 of the photomultiplier tubes26 (the ends of the photomultiplier tubes 26 to which the scintillatorsub-housings 37 and sensors 16 are attached) in the first row 62 facethe first ends 32 of the photomultiplier tubes 26 (the ends of thephotomultiplier tubes 26 to which the scintillator sub-housings 37 andsensors 16 are attached) in the row second 64. As used herein and in theappended claims, the first ends of the photomultiplier tubes in a firstrow “face” the first ends of the photomultiplier tubes in a second rowregardless of whether the sensors in the first row and the sensors inthe second row are vertically aligned to one another or verticallyoffset from one another.

FIG. 2B is a plan view in the form of a diagram 66 corresponding to thearrangement of the sensor assemblies 23 and sensors 16 shown in FIG. 2A.The diagram 66 shows the gamma ray measurement area 68 associated withthe sensors 16 and the recorded points 70 (the actual measurementpoints), that is points that correspond to the locations of the sensorson the logging tool body 12 (the locations where gamma ray data isactually sensed). The diagram 66 also includes lines of calculation 72which are the lines on which gamma ray data can be calculated byinterpolating the recorded points 70. For example, the diagram 66 alsoshows calculated points 73 on lines of calculation 72, that is points atwhich gamma ray data has been calculated based on interpolation of therecorded points 70. For example, the diagram 66 also shows sharedcalculated points 74 on lines of calculation 72, that is points at whichgamma ray data has been calculated based on interpolation of at leasttwo sets of calculated points 73.

Referring now to FIG. 3A, another embodiment of the passive cased wellimage logging tool assembly 10 will be described. This embodiment is thesame as the embodiment shown by FIG. 2A, except in this embodiment thesensor assemblies 23 and corresponding sensors 16 in one row are notvertically aligned to the sensor assemblies and corresponding sensors inthe other row. Rather, as shown by FIG. 3A, the sensor assemblies 23 andcorresponding sensors 16 in one row are vertically offset from thesensor assemblies and corresponding sensors in the other row. Forexample, the sensor assemblies 23 and corresponding sensors 16 in onerow can be vertically and equidistantly offset from the sensorassemblies and corresponding sensors in the other row. Specifically, sixsensor assemblies 23 and corresponding sensors 16 are linearly arrangedand equally spaced around the central longitudinal axis 14 of thelogging tool body 12 in a plane 75 a perpendicularly extending from thecentral longitudinal axis of the logging tool body and in a first row76. Also, six sensor assemblies 23 are linearly arranged and equallyspaced around the central longitudinal axis 14 of the logging tool body12 in a plane 75 b perpendicularly extending from the centrallongitudinal axis of the logging tool body and in a second row 78. Thesensor assemblies 23 and corresponding sensors 16 in the first row 76are vertically offset from the sensor assemblies and correspondingsensors in the second row 78.

As shown by FIG. 3A, the sensor assemblies 23 in each of the rows 76 and78 are arranged such that the first ends 32 of the photomultiplier tubes26 (the ends of the photomultiplier tubes 26 to which the scintillatorsub-housings 37 and sensors 16 are attached) in the first row 76 facethe first ends 32 of the photomultiplier tubes 26 (the ends of thephotomultiplier tubes 26 to which the scintillator sub-housings 37 andsensors 16 are attached) in the row second 78. When two rows of gammaray radiation sensor assemblies 23 and corresponding sensors 16 areequally spaced around the logging tool body 12, and the sensors in onerow are equidistantly offset from the sensors in the other row along thelongitudinal axis 14 of the logging tool body, maximum coverage of theinside of the casing can be achieved.

FIG. 3B is a plan view in the form of a diagram 84 corresponding to thearrangement of the sensor assemblies 23 and corresponding sensors 16shown in FIG. 3A. The diagram 84 shows the gamma ray measurement area 86associated with the sensors 16 and the recorded points 88 (the actualmeasurement points), that is points that correspond to the locations ofthe sensors on the logging tool body 12 (the locations where gamma raydata is actually sensed). The diagram 84 also includes lines ofcalculation 90 which are the lines on which gamma ray data can becalculated by interpolating the recorded points 88. For example, thediagram 84 also shows calculated points 92 on lines of calculation 90,that is points at which gamma ray data has been calculated based oninterpolation of the recorded points 88.

Referring now to FIG. 4A, another embodiment of the passive cased wellimage logging tool assembly 10 will be described. This embodiment is thesame as the embodiment shown by FIG. 2A, except in this embodiment, thesensor assemblies 23 and corresponding sensors 16 in each row arevertically staggered and equally spaced around the central longitudinalaxis 14 of the logging tool body 12. Specifically, six sensor assemblies23 and corresponding sensors 16 are vertically staggered and equallyspaced around the central longitudinal axis 14 of the logging tool body12 in a plane 98 a perpendicularly extending from the centrallongitudinal axis of the logging tool body and in a first row 100. Also,six sensor assemblies 23 are vertically staggered and equally spacedaround the central longitudinal axis 14 of the logging tool body 12along a plane 98 b perpendicularly extending from the centrallongitudinal axis of the logging tool body and in a second row 102. Thesensor assemblies 23 and corresponding sensors 16 can also be verticallystaggered and equally spaced around the central longitudinal axis 14 ofthe logging tool body 12 in a single row.

As shown by FIG. 4A, the sensor assemblies 23 in each of the rows 100and 102 are arranged such that the first ends 32 of the photomultipliertubes 26 (the ends of the photomultiplier tubes 26 to which thescintillator sub-housings 37 and sensors 16 are attached) in the firstrow 100 face the first ends 32 of the photomultiplier tubes 26 (the endsof the photomultiplier tubes 26 to which the scintillator sub-housings37 and sensors 16 are attached) in the row second 102. The sensorassemblies 23 and corresponding sensors 16 in each row are arranged inalternating longitudinal positions 104 around the logging tool body withrespect to the central longitudinal axis 14 of the logging tool body 12.The sensor assemblies 23 and corresponding sensors 16 in the first row100 are vertically aligned to the sensor assemblies 23 and correspondingsensors 16 in the second row 102.

FIG. 4B is a plan view in the form of a diagram 110 corresponding to thearrangement of the sensor assemblies 23 and sensors 16 shown in FIG. 4A.The diagram 110 shows the gamma ray measurement area 112 associated withthe sensors 16 and the recorded points 114 (the actual measurementpoints), that is points that correspond to the locations of the sensors16 on the logging tool body 12 (the locations where gamma ray data isactually sensed). The diagram 110 also includes lines of calculation 118which are the lines on which gamma ray data can be calculated byinterpolating the recorded points 114. For example, the diagram 110 alsoshows calculated points 120 on lines of calculation 118, that is pointsat which gamma ray data has been calculated based on interpolation ofthe recorded points 114. For example, the diagram 110 also shows sharedcalculated points 122 on lines of calculation 118, that is points atwhich gamma ray data has been calculated based on interpolation of atleast two sets of calculated points 120. By interpolating the data intwo ways and averaging the results, the shared calculated points 122 aremore accurate.

Referring now to FIG. 5A, another embodiment of the passive cased wellimage logging tool assembly 10 will be described. In this embodiment,six sensor assemblies 23 and corresponding sensors 16 are helicallyarranged and equally spaced around the central longitudinal axis 14 ofthe logging tool body 12 in a plane 128 perpendicularly extending fromthe central longitudinal axis of the logging tool body and in a row 130to form a single-row right-handed helical arrangement 132 on the loggingtool body. The sensor assemblies 23 are directly attached to the loggingtool body 12.

FIG. 5B is a plan view in the form of a diagram 134 corresponding to aportion of the arrangement of the sensor assemblies 23 and sensors 16shown in FIG. 5A. The diagram 134 shows the gamma ray measurement area136 associated with the corresponding sensors 16 and the recorded points138 (the actual measurement points), that is points that correspond tothe locations of the corresponding sensors on the logging tool body 12(the locations where gamma ray data is actually sensed). The diagram 134also includes lines of calculation 140 which are the lines on whichgamma ray data can be calculated by interpolating the recorded points138. For example, the diagram 134 also shows calculated points 142 onlines of calculation 140, that is points at which gamma ray data hasbeen calculated based on interpolation of the recorded points 138.

Referring now specifically to FIG. 6A, another embodiment of the passivecased well image logging tool assembly 10 will be described. In thisembodiment, six sensor assemblies 23 and corresponding sensors 16 arehelically arranged and equally spaced around the central longitudinalaxis 14 of the logging tool body 12 in a plane 150 a perpendicularlyextending from the central longitudinal axis of the logging tool bodyand in a first row 152. Six sensor assemblies 23 and correspondingsensors 16 are also helically arranged and equally spaced around thecentral longitudinal axis 14 of the logging tool body 12 in a plane 150b perpendicularly extending from the central longitudinal axis of thelogging tool body and in a second row 153, to form a two-rowright-handed helical arrangement 154 on the logging tool body. Thesensor assemblies 23 are directly attached to the logging tool body 12.The sensor assemblies 23 and corresponding sensors 16 in the first row152 are vertically aligned to the sensor assemblies 23 and correspondingsensors 16 in the second row 153.

As shown by FIG. 6A, the sensor assemblies 23 in each of the rows 152and 153 are arranged such that the first ends 32 of the photomultipliertubes 26 (the ends of the photomultiplier tubes 26 to which thescintillator sub-housings 37 and sensors 16 are attached) in the firstrow 152 face the first ends 32 of the photomultiplier tubes 26 (the endsof the photomultiplier tubes 26 to which the scintillator sub-housings37 and sensors 16 are attached) in the second row 153. The sensorassemblies 23 and sensors 16 in the first row 152 are vertically alignedto the sensor assemblies 23 and sensors 16 in the second row 153.

FIG. 6B is a plan view in the form of a diagram 155 corresponding to aportion of the arrangement of the sensor assemblies 23 and sensors 16shown in FIG. 6A. The diagram 155 shows the gamma ray measurement area156 associated with the corresponding sensors 16 and the recorded points158, that is points that correspond to the locations of thecorresponding sensors on the logging tool body 12 (the locations wheregamma ray data is actually sensed). The diagram 155 also includes linesof calculation 160 which are the lines on which gamma ray data can becalculated by interpolating the recorded points 158. For example, thediagram 155 also shows calculated points 162 on lines of calculation160, that is points at which gamma ray data has been calculated based oninterpolation of the recorded points 158. For example, the diagram 155also shows shared calculated points 164 on lines of calculation 160,that is points at which gamma ray data has been calculated based oninterpolation of at least two sets of calculated points 162. Forexample, the diagram 155 also shows extra calculated points 166 on linesof calculation 160, that is points at which gamma ray data has beencalculated based on interpolation of other calculated points.

Referring now to FIG. 7A, another embodiment of the passive cased wellimage logging tool assembly 10 will be described. This embodiment issimilar to the embodiment shown by FIG. 6A, except in this embodiment,the logging tool assembly 10 includes two sets of gamma ray radiationsensor assemblies 23 and sensors 16, a first set 170 and a second set172. As shown by FIG. 7A, in each of the sets 170 and 172, the sensorassemblies 23 and sensors 16 are helically arranged and equally spacedaround the central longitudinal axis 14 of the logging tool body 12 in aplane 174 a perpendicularly extending from the central longitudinal axisof the logging tool body 12 and in a first row 176, and are helicallyarranged and equally spaced around the central longitudinal axis of thelogging tool body in a plane 174 b perpendicularly extending from thecentral axis of the logging tool body and in a second row 178, to form atwo-row right-handed helical arrangement 180 on the logging tool body.The sensor assemblies 23 in each of the sets 170 and 172 are directlyattached to the logging tool body 12. The sensor assemblies 23 andsensors 16 in the first row 176 are vertically aligned to the sensorassemblies 23 and corresponding sensors 16 in the second row 178. Asoriented in the drawings, the set 170 is on top of the set 172 on thelogging tool body 12.

As shown by FIG. 7A, in each of the sets 170 and 172, the sensorassemblies 23 in each of the rows 176 and 178 are arranged such that thefirst ends 32 of the photomultiplier tubes 26 (the ends of thephotomultiplier tubes 26 to which the scintillator sub-housings 37 andsensors 16 are attached) in the first row 176 face the first ends 32 ofthe photomultiplier tubes 26 (the ends of the photomultiplier tubes 26to which the scintillator sub-housings 37 and sensors 16 are attached)in the second row 178. The sensor assemblies 23 and sensors 16 in thefirst row 176 are vertically aligned to the sensor assemblies 23 andsensors 16 in the second row 178.

FIG. 7B is a plan view in the form of a diagram 185 corresponding to aportion of the arrangement of the sensor assemblies 23 and sensors 16 ineach of the sets 170 and 172 shown in FIG. 7A. The diagram 185 shows thegamma ray measurement area 186 associated with the corresponding sensors16 and the recorded points 188, that is points that correspond to thelocations of the corresponding sensors on the logging tool body 12 (thelocations where gamma ray data is actually sensed). The diagram 185 alsoincludes lines of calculation 190 which are the lines on which gamma raydata can be calculated by interpolating the recorded points 188. Forexample, the diagram 185 also shows calculated points 192 on lines ofcalculation 190, that is points at which gamma ray data has beencalculated based on interpolation of the recorded points 188. Forexample, the diagram 185 also shows shared calculated points 194 onlines of calculation 190, that is points at which gamma ray data hasbeen calculated based on interpolation of at least two sets ofcalculated points 192. For example, the diagram 185 also shows extracalculated points 196 on lines of calculation 190, that is points atwhich gamma ray data has been calculated based on interpolation of othercalculated points.

Referring now to FIG. 8A, another embodiment of the passive cased wellimage logging tool assembly 10 will be described. This embodiment is thesame in all respects to the embodiment shown by FIG. 7A, except in thisembodiment, the sensor assemblies 23 and corresponding sensors 16 in thesecond set 172 are helically arranged to form a two-row left-handedhelical arrangement 200 around the central longitudinal axis 14 of thelogging tool body 12. Thus, the sensor assemblies 23 and sensors 16 arehelically arranged to form a two-row right-handed helical arrangement180 in the first set 170, and are arranged to form a two-row left-handedhelical arrangement 200 in the second set 172. As oriented in thedrawings, the set 170 is on top of the set 172 on the logging tool body12.

FIG. 8B is a plan view in the form of a diagram 205 corresponding to aportion of the arrangement of the sensor assemblies 23 and sensors 16shown in each of the sets 170 and 172 in FIG. 8A. The diagram 205 showsthe gamma ray measurement area 206 associated with the correspondingsensors 16 and the recorded points 208, that is points that correspondto the locations of the corresponding sensors on the logging tool body12 (the locations where gamma ray data is actually sensed). The diagram205 also includes lines of calculation 210 which are the lines on whichgamma ray data can be calculated by interpolating the recorded points208. For example, the diagram 205 also shows calculated points 212 onlines of calculation 210, that is points at which gamma ray data hasbeen calculated based on interpolation of the recorded points 208. Forexample, the diagram 205 also shows shared calculated points 214 onlines of calculation 210, that is points at which gamma ray data hasbeen calculated based on interpolation of at least two sets ofcalculated points 212.

Referring now to FIGS. 9A and 9B, another embodiment of the passivecased well image logging tool assembly 10 will be described. Thisembodiment is similar to the embodiment shown by FIG. 6A, except in thisembodiment, there are only four sensor assemblies 23 and correspondingsensors 16 in each row. Specifically, four sensor assemblies 23 andcorresponding sensors 16 are helically arranged and equally spacedaround the central longitudinal axis 14 of the logging tool body 12 in aplane 220 a perpendicularly extending from the central longitudinal axisof the logging tool body and in a first row 222 a. Also, four sensorassemblies 23 and corresponding sensors 16 are helically arranged andequally spaced around the central longitudinal axis 14 of the loggingtool body 12 in a plane 220 b perpendicularly extending from the centralaxis of the logging tool body and in a second row 222 b, to form atwo-row right-handed helical arrangement 223 on the logging tool body.The sensor assemblies 23 are directly attached to the logging tool body12. The sensor assemblies 23 and corresponding sensors 16 in the firstrow 222 a are vertically aligned to the sensor assemblies 23 andcorresponding sensors 16 in the second row 222 b.

As shown by FIG. 9A, the sensor assemblies 23 in each of the rows 222 aand 222 b are arranged such that the first ends 32 of thephotomultiplier tubes 26 (the ends of the photomultiplier tubes 26 towhich the scintillator sub-housings 37 and sensors 16 are attached) inthe first row 222 a face the first ends 32 of the photomultiplier tubes26 (the ends of the photomultiplier tubes 26 to which the scintillatorsub-housings 37 and sensors 16 are attached) in the second row 222 b.The sensor assemblies 23 and sensors 16 in the first row 222 a arevertically aligned to the sensor assemblies 23 and sensors 16 in thesecond row 222 b.

FIG. 10 illustrates the flow of wellbore fluid (for example, kill fluid)around and through the logging tool assembly when a helical arrangementof sensor assemblies and sensors is utilized in association with thelogging tool assembly disclosed herein. For example, at any point, onlyone sensor assembly 23 will be blocking 100% of the flow. Two sensorassemblies 23 will be blocking 50% of the flow, and four sensorassemblies will be blocking 25% of the flow. Thus, there is always a gapfor wellbore fluid to flow through, which, for example, allows thelogging tool assembly to be more easily moved through the wellbore.

As shown by FIGS. 1-10, the housings 24 of the sensor assemblies 23contain the sensors 16 and photomultiplier tubes 26. For example, asshown, each housing 24 is a cylindrical tube having a diameter of lessthan an inch and a length of about six inches. The central longitudinalaxis 28 of the housing 24, as well as the central longitudinal axis 38of the scintillator sub-housing 37 and the central longitudinal axis 30of the photomultiplier tube 26, extend along and are parallel to thecentral longitudinal axis 14 of the logging tool body 12. When two rowsof sensor assemblies 23 are used, the sensor assemblies andcorresponding sensors 16 face each other (either in alignment with eachother or offset from one another).

However, as shown by FIGS. 11A-11C and FIGS. 12A-12C, the size and shapeof the sensor assemblies as well as the manner in which the sensorassemblies 23 are oriented with respect to the logging tool body 12 canvary. For example, the embodiment of the logging tool assembly 10 shownby FIGS. 11A-11C is similar to the embodiment of the logging toolassembly shown by FIG. 5A, except for the size, shape and orientation ofthe sensor assemblies 23. In the embodiment shown by FIGS. 11A-11C, thecentral longitudinal axis 30 of the photomultiplier tube 26 of eachsensor assembly 23 extends parallel to the central longitudinal axis 14of the logging tool body 12. However, the central longitudinal axis 38of the corresponding scintillator sub-housing 37 of each sensor assembly23 extends perpendicularly outwardly from the central longitudinal axis30 of the corresponding photomultiplier tube 26 and the centrallongitudinal axis 14 of the logging tool body 12. Such an “L”configuration of the sensor assemblies 23 can alter the final assemblyorientation in the logging tool body 12, and can allow the size of thesensors 16 to be increased.

For example, the embodiment of the logging tool assembly 10 shown byFIG. 12A-12C is similar to the embodiment of the logging tool assemblyshown by FIG. 5A, except for the size, shape and orientation of thescintillator sub-housings 37 and corresponding sensors 16. In theembodiment shown by FIGS. 12A-12C, the central longitudinal axis 30 ofthe photomultiplier tube 26 of each sensor assembly 23 extends parallelto the central longitudinal axis 14 of the logging tool body 12. Thecentral longitudinal axis 38 of the scintillator sub-housing 37 of eachsensor subassembly extends parallel to both the central longitudinalaxis 30 of the corresponding photomultiplier tube 26 and the centrallongitudinal axis 14 of the logging tool body. However, the size andshape of the scintillator sub-housing 37 of each sensor assembly 23 ofthe embodiment shown by FIGS. 12A-12C is different. For example, asshown, each scintillator sub-housing 37 is larger and has a wedge shape.Specifically, the scintillator sub-housing 37 of each sensor assembly 23of the embodiment shown by FIGS. 12A-12C includes a base 224 a facingthe central core 42 of the logging tool assembly 10 and a face 224 afacing the inside surface 41 b of the outer sheath 40 of the loggingtool assembly. The central horizontal axis 226 of each scintillatorsub-housing 37 extends perpendicularly outwardly from the centrallongitudinal axis 38 of the scintillator sub-housing, the centrallongitudinal axis 30 of the corresponding photomultiplier tube 26 andthe central longitudinal axis 14 of the logging tool body. Such a wedgeshape can alter the final assembly orientation in the logging tool body12, and can allow the size of the sensors 16 to be increased. Forexample, scintillation crystals can fill the entire volume of thescintillator sub-housing 37.

For example, when six sensors 16 are utilized, the coverage of eachsensor is typically 60° per sensor making the collective coverage of thesensors the 360° perimeter around the logging tool assembly 10. On theother hand, for example, in a helical arrangement, larger sensors can beused (as shown by FIGS. 11A-11C and 12A-12C) allowing the focus of eachsensor to overlap which makes the collective coverage around theperimeter of the logging tool assembly 10 greater than 360°.

The size and shape of the sensor assemblies 23 and individual componentsthereof as well as the manner in which the sensor assemblies 23 andindividual components thereof are oriented can vary within a singlearrangement of sensor assemblies around the central longitudinal axis 14of the logging tool body. For example, in a two row helical arrangement,one or more sensor assemblies of the type shown by FIG. 5A can becombined with one or more of the sensor assemblies of the types shown byFIG. 11A and FIG. 12A.

FIG. 13 schematically illustrates the transmission of gamma rayradiation data from sensor assemblies 23 of the logging tool assembly 10to a recording device 227 remote from the sensor assemblies. Forexample, the recording device can be part of the logging tool assembly12 or can be located on the surface associated with the well.

FIGS. 14A and 14B illustrate the passive cased well image logging toolassembly 10 shown by FIGS. 3A and 3B positioned downhole in a wellbore228 that includes a borehole 230 and penetrates a subterranean formation231. As shown, the wellbore 228 includes an annular casing 232surrounded by an annular cement sheath 234. The annular cement sheath234 surrounds the casing 232 and separates the casing 232 from theformation 231. For example, the casing 232 can be formed of metal. Theoutside diameter 238 of the logging tool assembly 10 is slightly lessthan the internal diameter 239 of the casing.

FIG. 14B illustrates the focus areas 240 of the sensors 16 of the sensorassemblies 23 associated with the logging tool assembly 10 and a “shadowzone” 242 behind each sensor. The focus areas 240 are primarily dictatedby the size and angle associated with the windows 36 of the housings 24of the sensor assemblies 23. The shadow zone 242 represents a shadoweffect that the central core 42 of the logging tool assembly 10 can haveon the arrangement of the sensor assemblies 23 and corresponding sensors16. For example, when a sensor 16 on one side of the logging tool body12 is receiving radiation, the central core 42 can totally block thesensor 16 on the opposing side of the logging tool body and therebyimprove the signal-to-noise ratio.

FIG. 15 is a schematic view illustrating an example of use of thepassive cased well image logging tool assembly 10 in accordance with oneembodiment of the method disclosed herein. The logging tool assembly 10is lowered into and pulled out of the wellbore 228 using a wirelinecable 250 that is operated by a wireline or logging truck 252 in amanner that will be understood by those skilled in the art with thebenefit of this disclosure. The attachment assembly 54 of the loggingtool assembly 10 is attached to an end 254 of the wireline cable 250.

The annular casing 232 is cemented in place in the wellbore 230 to thetotal depth of the wellbore. The wellbore 228 is surrounded by aplurality of geologic units 260. As shown, the geologic units 260include wet sand zones 260 a, a shale zone 260 b, a hydrocarbon-richsand zone (pay zone) 260 c, and a silty shale zone 260 d. The geologicunits 260 and the borehole 230 are traversed by a normal fault 262 (ageological event). Motion/fault direction arrows 264 illustrate thedirection of motion associated with the normal fault 262.

As shown by the drawings, the sensor assemblies 23 are directly attachedto the logging tool body 12. For example, the sensor assemblies can beattached to the inside surface 41 b of the outer sheath 40 and/or thecentral core 42. The sensor assemblies 23 can be attached to the loggingtool body 12 in other ways as well.

Once the logging tool assembly 10 is being lowered to the desired depthin the borehole 230, the logging process can be initiated. For example,the logging tool assembly 10 can be operated to begin the loggingprocess by sending a signal through the wireline cable 250 to the toolassembly 10. The logging tool assembly 10 is pulled out of the borehole230 by the wireline truck 252 and wireline cable 250 at a desiredlogging speed. While the tool assembly 10 is being pulled out of theborehole 230 at the desired logging speed, it collects gamma rayradiation data using a desired counting time at a desired sampling rate.For example, gamma rays naturally emitted by the formation come into thesensors 16 and impact the sensors. For example, when the sensors 16 arescintillation crystals, the gamma rays impact the crystals to create oneor more flashes therein. The flashes are enhanced by the photomultipliertubes 26. In other words, the photomultiplier tubes 26 amplify thesensor flashes to give better sensor readings. The data is correctedusing data from the spatial positioning device 18 and otherwiseprocessed in a manner that will be understood by those skilled in theart with the benefit of this disclosure. A well image log is thenprepared based on the collected data.

FIG. 16 is an example of a well image log 280 that can be created usingthe method and passive cased well logging tool assembly disclosedherein. As shown, the well image log 280 provides an unwrapped wellboreimage 282 with interpreted data regarding the intensity of the gamma rayradiation at different points in the geologic units 260. Due to the factthe log 280 provides an “unwrapped view,” what is seen on the 0/360 line284 a is also seen on the 360/0 line 284 b. The image 282 includesstructural axes 286 and several image tracks 288 across the borehole230. Increasing the number of sensor assemblies 23 and sensors 16 on thelogging tool assembly 10 will decrease the blank spaces 290 between thetracks 288. An increase in the internal diameter 239 of the casing 232will widen the non-image tracks; however, for larger holes the tool mayoperate better if it includes additional sensor assemblies 23 andcorresponding sensors 16. The final images can be used to interpretgeologic events, boundaries, faults, fractures and dip and azimuth.

Thus, for example, in one embodiment, the method of creating a wellimage log of a cased well disclosed herein comprises: (a) providing apassive cased well image logging tool assembly, the logging toolassembly including: (1) an elongated logging tool body having a centrallongitudinal axis; a plurality of sensor assemblies attached to thelogging tool body and equally spaced around the central longitudinalaxis of logging tool body, each sensor assembly including: (i) ahousing; (ii) a gamma ray radiation sensor contained by the housing, thesensor being capable of continuously collecting gamma ray radiation datafrom one or more geologic units surrounding or adjacent to the wellboreas the logging tool assembly is moved through the wellbore, wherein thegamma ray radiation sensor is a gamma ray radiation scintillationcrystal; and (iii) a photomultiplier tube associated with the sensor,the photomultiplier tube having a central longitudinal axis, a firstend, and a second end, wherein the sensor is attached to one end of thecorresponding photomultiplier tube; and (2) at least one spatialpositioning device attached to the logging tool body that is capable ofcontinuously collecting sensor position data reflecting the xyz spatialposition of the sensors in the wellbore relative to the wellbore and theEarth as the logging tool assembly is moved through the wellbore; (b)moving the logging tool assembly through at least a portion of thewellbore; (c) as the logging tool assembly is being moved through thewellbore, using the sensors to continuously collect gamma ray radiationdata that is emitted by the geologic unit(s); (d) as the logging toolassembly is being moved through the wellbore, using the spatialpositioning device to continuously collect sensor position datareflecting the xyz spatial position of the sensors within the wellborerelative to the wellbore and the Earth; (e) using the collected sensorposition data to correct the collected gamma ray radiation data; (f)vertically sampling the corrected gamma ray radiation data; and (g)preparing a well image log based on the sampled gamma ray radiationdata.

In another embodiment, the method of creating a well image log of acased well disclosed herein comprises: (a) providing a passive casedwell image logging tool assembly, the logging tool assembly including:(1) an elongated logging tool body having a central longitudinal axis; aplurality of sensor assemblies attached to the logging tool body andequally spaced around the central longitudinal axis of the logging toolbody, each sensor assembly including: (i) a housing; (ii) a gamma rayradiation sensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and(iii) a photomultiplier tube associated with the sensor, thephotomultiplier tube having a central longitudinal axis, a first end,and a second end, wherein the sensor is attached to one end of thecorresponding photomultiplier tube, wherein the gamma ray radiationsensors are linearly arranged and equally spaced around the centrallongitudinal axis of the logging tool body in two rows, wherein thegamma ray radiation sensors in each of the rows are arranged such thatthe ends of the photomultiplier tubes containing the sensors in one rowface the ends of the photomultiplier tubes containing the sensors in theother row, and wherein the gamma ray radiation sensors in one of therows are vertically aligned to the sensors in the other row; and (2) atleast one spatial positioning device attached to the logging tool bodythat is capable of continuously collecting sensor position datareflecting the xyz spatial position of the sensors in the wellborerelative to the wellbore and the Earth as the logging tool assembly ismoved through the wellbore; (b) moving the logging tool assembly throughat least a portion of the wellbore; (c) as the logging tool assembly isbeing moved through the wellbore, using the sensors to continuouslycollect gamma ray radiation data that is emitted by the geologicunit(s); (d) as the logging tool assembly is being moved through thewellbore, using the spatial positioning device to continuously collectsensor position data reflecting the xyz spatial position of the sensorswithin the wellbore relative to the wellbore and the Earth; (e) usingthe collected sensor position data to correct the collected gamma rayradiation data; (f) vertically sampling the corrected gamma rayradiation data; and (g) preparing a well image log based on the sampledgamma ray radiation data.

In another embodiment, the method of creating a well image log of acased well disclosed herein comprises: (a) providing a passive casedwell image logging tool assembly, the logging tool assembly including:(1) an elongated logging tool body having a central longitudinal axis; aplurality of sensor assemblies attached to the logging tool body andequally spaced around the central longitudinal axis of the logging toolbody, each sensor assembly including: (i) a housing; (ii) a gamma rayradiation sensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and(iii) a photomultiplier tube associated with the sensor, thephotomultiplier tube having a central longitudinal axis, a first end,and a second end, wherein the sensor is attached to one end of thecorresponding photomultiplier tube, wherein the gamma ray radiationsensors are linearly arranged and equally spaced around the centrallongitudinal axis of the logging tool body in two rows, wherein thegamma ray radiation sensors in each of the rows are arranged such thatthe ends of the photomultiplier tubes containing the sensors in one rowface the ends of the photomultiplier tubes containing the sensors in theother row, and wherein the gamma ray radiation sensors in one of therows are vertically offset from the sensors in the other row; and (2) atleast one spatial positioning device attached to the logging tool bodythat is capable of continuously collecting sensor position datareflecting the xyz spatial position of the sensors in the wellborerelative to the wellbore and the Earth as the logging tool assembly ismoved through the wellbore; (b) moving the logging tool assembly throughat least a portion of the wellbore; (c) as the logging tool assembly isbeing moved through the wellbore, using the sensors to continuouslycollect gamma ray radiation data that is emitted by the geologicunit(s); (d) as the logging tool assembly is being moved through thewellbore, using the spatial positioning device to continuously collectsensor position data reflecting the xyz spatial position of the sensorswithin the wellbore relative to the wellbore and the Earth; (e) usingthe collected sensor position data to correct the collected gamma rayradiation data; (f) vertically sampling the corrected gamma rayradiation data; and (g) preparing a well image log based on the sampledgamma ray radiation data.

In one embodiment, the passive cased well image logging tool assemblyfor use in a cased well disclosed herein comprises: (a) an elongatedlogging tool body having a central longitudinal axis; (b) a plurality ofsensor assemblies attached to the logging tool body and equally spacedaround the central longitudinal axis of the logging tool body, eachsensor assembly including: (1) a housing; (2) a gamma ray radiationsensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and (3)a photomultiplier tube associated with the sensor, the photomultipliertube having a central longitudinal axis, a first end, and a second end,wherein the sensor is attached to one end of the correspondingphotomultiplier tube, wherein the gamma ray radiation sensors arelinearly arranged and equally spaced around the central longitudinalaxis of the logging tool body in two rows, wherein the gamma rayradiation sensors in each of the rows are arranged such that the ends ofthe photomultiplier tubes containing the sensors in one row face theends of the photomultiplier tubes containing the sensors in the otherrow, and wherein the gamma ray radiation sensors in one of the rows arevertically aligned to the sensors in the other row; and (c) at least onespatial positioning device attached to the logging tool body that iscapable of continuously collecting sensor position data reflecting thexyz spatial position of the gamma ray radiation sensors in the wellborerelative to the wellbore and the Earth as the logging tool assembly ismoved through the wellbore.

In another embodiment, the passive cased well image logging toolassembly for use in a cased well disclosed herein comprises: (a) anelongated logging tool body having a central longitudinal axis; (b) aplurality of sensor assemblies attached to the logging tool body andequally spaced around the central longitudinal axis of the logging toolbody, each sensor assembly including: (1) a housing; (2) a gamma rayradiation sensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and (3)a photomultiplier tube associated with the sensor, the photomultipliertube having a central longitudinal axis, a first end, and a second end,wherein the sensor is attached to one end of the correspondingphotomultiplier tube, wherein the gamma ray radiation sensors arelinearly arranged and equally spaced around the central longitudinalaxis of the logging tool body in two rows, wherein the gamma rayradiation sensors in each of the rows are arranged such that the ends ofthe photomultiplier tubes containing the sensors in one row face theends of the photomultiplier tubes containing the sensors in the otherrow, and wherein the gamma ray radiation sensors in one of the rows arevertically offset from the sensors in the other row; and (c) at leastone spatial positioning device attached to the logging tool body that iscapable of continuously collecting sensor position data reflecting thexyz spatial position of the gamma ray radiation sensors in the wellborerelative to the wellbore and the Earth as the logging tool assembly ismoved through the wellbore.

In another embodiment, the passive cased well image logging toolassembly for use in a cased well disclosed herein comprises: (a) anelongated logging tool body having a central longitudinal axis; (b) aplurality of sensor assemblies attached to the logging tool body andequally spaced around the central longitudinal axis of the logging toolbody, each sensor assembly including: (1) a housing; (2) a gamma rayradiation sensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and (3)a photomultiplier tube associated with the sensor, the photomultipliertube having a central longitudinal axis, a first end, and a second end,wherein the sensor is attached to one end of the correspondingphotomultiplier tube, wherein the gamma ray radiation sensors arevertically staggered and equally spaced around the central longitudinalaxis of the logging tool body in two rows and wherein the gamma rayradiation sensors in each of the rows are arranged such that the ends ofthe photomultiplier tubes containing the sensors in one row face theends of the photomultiplier tubes containing the sensors in the otherrow; and (c) at least one spatial positioning device attached to thelogging tool body that is capable of continuously collecting sensorposition data reflecting the xyz spatial position of the gamma rayradiation sensors in the wellbore relative to the wellbore and the Earthas the logging tool assembly is moved through the wellbore.

In another embodiment, the passive cased well image logging toolassembly for use in a cased well disclosed herein comprises: (a) anelongated logging tool body having a central longitudinal axis; (b) aplurality of sensor assemblies attached to the logging tool body andequally spaced around the central longitudinal axis of the logging toolbody, each sensor assembly including: (1) a housing; (2) a gamma rayradiation sensor contained by the housing, the sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, wherein the gamma rayradiation sensor is a gamma ray radiation scintillation crystal; and (3)a photomultiplier tube associated with the sensor, the photomultipliertube having a central longitudinal axis, a first end, and a second end,wherein the sensor is attached to one end of the correspondingphotomultiplier tube, wherein the gamma ray radiation sensors arehelically arranged and equally spaced around the central longitudinalaxis of the logging tool body in two rows and wherein the gamma rayradiation sensors in each of the rows are arranged such that the ends ofthe photomultiplier tubes containing the sensors in one row face theends of the photomultiplier tubes containing the sensors in the otherrow; and (c) at least one spatial positioning device attached to thelogging tool body that is capable of continuously collecting sensorposition data reflecting the xyz spatial position of the gamma rayradiation sensors in the wellbore relative to the wellbore and the Earthas the logging tool assembly is moved through the wellbore.

Many advantages are achieved by the method and logging tool assemblydisclosed herein. For example, the increased number of sensors 16 andspecific arrangements thereof on the logging tool body 12 increase thequality of the data collected and provided by the tool. The variousarrangements of the sensor assemblies 23 and corresponding sensors 16disclosed herein allow additional sensor points to be calculated, whichfurther increases the quality of the data collected and provided by thetool. Also, the various arrangements of the sensor assemblies 23 andcorresponding sensors 16 allow larger sensors, including largerscintillation crystals, to be used which means more accurate data isprovided by the logging tool assembly 10. Statistics and spatialcalculations are improved, the signal-to-noise ratio is increased, theposition of incoming signals can be more precisely calculated, and abetter image of the borehole wall can be created. For example, by havingthe sensors 16 placed in basically a parallelogram shape (for example,in connection with the helical arrangements of sensors), the number ofinterpolated points between the sensors can be increased. For example,actual data points from six actual sensors 16 can be combined with ninecalculated data points (interpolated points). The various arrangementsof the sensor assemblies 23 and sensors 16 disclosed herein also allowthe size of the crystals to be as large as possible.

The ultimate goal of any image logging tool is to get an accuraterepresentation of characteristics of the geologic units surrounding thewellbore. By using the passive well image logging tool assemblydisclosed herein in accordance with the disclosed method, a highlyoriented logging survey can be conducted to collect useful wellbore andgeologic unit data. For example, by combining a low logging speed withthe minimum offset produced by multiple radially arranged radiationsensor assemblies biased against the inner wall of the wellbore casing,and eliminating interference by mud filter cake, drilling fluid andother factors that are present in an open-hole environment, better datacan be collected in accordance with the disclosed method with a higherS/N ratio, which allows for the acquisition of more useable dataresulting in an improved image and interpretation.

By detecting and receiving gamma ray radiation data emitted fromgeologic units surrounding or adjacent to the wellbore and using suchdata to generate a well image log, the method disclosed herein has manyadvantages over micro-resistivity, acoustical, optical and other imagelogging methods used heretofore. For example, using naturally-occurringgamma ray radiation data emitted from geologic units to derive theneeded information allows a passive cased well logging tool to be usedin a cased wellbore. Gamma ray radiation data (for example, fromnaturally occurring gamma rays or injected tracer gamma rays) can becollected without emitting any signal from the well logging toolassembly through the wellbore casing into the surrounding geologicunits. As a result, the regulatory issues associated with using anactive-source image logging tool assembly and the tremendous problemsthat can result if such a tool gets stuck (e.g., due to hole rugosity,differential pressure sticking, wellbore deviations or “dog-legs,”and/or other material in the wellbore) can be avoided.

Perhaps most importantly, using naturally occurring gamma ray radiationdata emitted from geologic units penetrated by the wellbore to derivethe needed information allows the method disclosed herein to be carriedout and the image logging tool disclosed herein to be used in connectionwith wellbores that have already been cased, for example, many yearsago. For example, metal, plastic and composite casings do not interferewith naturally occurring gamma ray radiation transmitted from thegeologic units through the wellbore to the image logging tool assemblydisclosed herein. This creates numerous advantages over methods and welllogging tool assemblies that directly measure theconductivity/resistivity or acoustic or optical properties of materialsin the geologic units and therefore cannot be used in a cased well.

The method and image logging tool assembly disclosed herein can be usedto create a well image log in a variety of different applications. Forexample, if a portion of the wellbore must be cased during the processof drilling a well (for example, due to unstable conditions caused by anunconsolidated zone), the well operator can 1) stop drilling, 2) pullthe drilling bit assembly out of the hole, 3) run a “protective” casingstring across the problem zone, 4) use the method and image logging toolassembly disclosed herein to log across that casing string, 5) run thedrilling bit assembly back to the bottom of the newly cased hole, and 6)continue drilling. As another example, the method and image well loggingtool assembly disclosed herein can be used in connection with active andinactive cased wells, and temporarily abandoned cased wells, includingcased wells drilled decades ago and for which a well image log is notavailable. For example, the potential viability of an abandoned well forfurther production or re-drilling using new technology can now beevaluated. Cased wells in use or used in the past as water productionwells and waste disposal wells can also be effectively evaluated.

For example, with the method and cased well image logging tool assemblydisclosed herein, there are no problems due to mud-cake build up on theborehole wall, high formation fluid invasion into the surrounding rockunit, or the type of drilling fluid used in the wellbore. In most cases,because the well has already been cased, the high cost of having adrilling rig in place is not a factor. The fear that the wellbore willcollapse or cave in is not a factor, which allows the data to beselectively collected at more optimal or non-critical times, thusfurther reducing costs and risks. The fear that the well logging toolwill get stuck due to the shape and rugosity of the hole is not afactor. As a result, the needed data can be collected at a relativelyslow logging speed and/or higher sampling rate as compared to thelogging speed and/or sampling rate that is used in connection with othermethods and well logging tools that are typically used in an open-holeenvironment.

In fact, the naturally occurring gamma ray radiation emitted by the rockand other elements in a geologic unit penetrated by the wellbore can bemore accurately collected at a lower logging speed. For example, a gammaray signal event boundary between sand and shale can be more accuratelydefined at a lower logging speed. The ability to collect the needed dataat a relatively slow speed, for example, a speed no greater than 750FPH, allows the data to be collected in accordance with the method andwell logging tool disclosed herein in a manner that provides, forexample, increased bed definition. This can be done without having toequip the well logging tool with a large number of highly sophisticatedsensor assemblies and signal processors. As a result, the passive casedwell image logging tool assembly disclosed herein does not have to be asrobust, sophisticated or expensive as other well logging tools that areused in an open-hole environment and must consequently be operated atsignificantly higher logging speeds.

The S/N ratio associated with the method and passive cased well imagelogging tool assembly disclosed herein is significantly improved byusing the tool assembly in a cased hole environment, by decreasing thelogging speed and thereby increasing the sampling rate associated withthe tool assembly. The S/N ratio associated with the method and passivecased well image tool assembly disclosed herein can be further improvedby increasing the number of gamma ray radiation sensor assembliesattached to the tool assembly, using one or more gyroscopes to spatiallycorrect the data collected by the tool assembly, radially aligningradiation sensor assemblies around the tool assembly to increase thecoverage of surrounding geologic units, positioning the sensorassemblies in a more optimal pattern, and biasing the sensor assembliesagainst the interior surface of the casing by using extendable arms.

The fact that the method and tool assembly disclosed herein can be usedin a cased well avoids the time constraints and costs associated withhaving a drilling rig in place and the limitations of an unstablewellbore or other conditions. Thus, the method and tool assembly can besafely used at a time when operational costs are less, time is moreavailable and when the wellbore is not in danger of collapsing.

The method and tool assembly disclosed herein can be used to assessolder cased wellbores, including horizontal wells, for possible re-drilland/or recompletion. The method and tool add value to wells that havebeen stimulated by fracturing and/or acidizing techniques by providingthe ability to qualitatively evaluate the stimulation results andidentify any uncompleted pay zones or potential accumulations accessedby re-drilling.

Therefore, the present method and logging tool assembly are well adaptedto attain the ends and advantages mentioned, as well as those that areinherent therein. The particular examples disclosed above areillustrative only, as the present method and logging tool assembly maybe modified and practiced in different but equivalent manners apparentto those skilled in the art having the benefit of the teachings herein.Furthermore, no limitations are intended to the details of constructionor design herein shown, other than as described in the claims below. Itis therefore evident that the particular illustrative examples disclosedabove may be altered or modified, and all such variations are consideredwithin the scope and spirit of the present treatment additives andmethods. While the method and logging tool assembly are described interms of “comprising,” “containing,” “having,” or “including” variouscomponents or steps, the method and logging tool assembly can also, insome examples, “consist essentially of” or “consist of” the variouscomponents and steps. Whenever a numerical range with a lower limit andan upper limit is disclosed, any number and any included range fallingwithin the range are specifically disclosed. In particular, every rangeof values (of the form, “from about a to about b,” or, equivalently,“from approximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood to set forth every number and rangeencompassed within the broader range of values. Also, the terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method of creating a well image log of a casedwell, comprising: providing a passive cased well image logging toolassembly, said logging tool assembly including: an elongated loggingtool body having a central longitudinal axis; a plurality of gamma rayradiation sensors attached to said logging tool body and spaced aroundsaid central longitudinal axis of said logging tool body, each gamma rayradiation sensor being capable of continuously collecting gamma rayradiation data from one or more geologic units surrounding or adjacentto the wellbore as said logging tool assembly is moved through thewellbore; and at least one spatial positioning device attached to saidlogging tool body that is capable of continuously collecting sensorposition data reflecting the xyz spatial position of said gamma rayradiation sensors in the wellbore relative to the wellbore and the Earthas said logging tool assembly is moved through the wellbore; moving saidlogging tool assembly through at least a portion of the wellbore; assaid logging tool assembly is being moved through the wellbore, usingsaid gamma ray radiation sensors to continuously collect gamma rayradiation data that is emitted by the geologic unit(s); as said loggingtool assembly is being moved through the wellbore, using said spatialpositioning device to continuously collect sensor position datareflecting the xyz spatial position of said gamma ray radiation sensorswithin the wellbore relative to the wellbore and the Earth; using saidcollected sensor position data to correct said collected gamma rayradiation data; sampling said corrected gamma ray radiation data,wherein said gamma radiation sensors are positioned relative to eachother so that said sampling said corrected gamma ray radiation dataproduces, at each of a plurality of sampling intervals, an areameasurement comprising recorded points and calculated points, whereinsaid calculated points are produced from measurements of gamma radiationcollected at two or more of said recorded points; and preparing a wellimage log based on said sampled gamma ray radiation data.
 2. The methodof claim 1, wherein said gamma ray radiation sensors are attached tosaid logging tool body and equally spaced around said centrallongitudinal axis of said logging tool body.
 3. The method of claim 1,wherein each of said sensors is a scintillation crystal.
 4. The methodof claim 1, wherein a sufficient number of gamma ray radiation sensorsare attached to said logging tool body and equally spaced around saidcentral longitudinal axis of said logging tool body to allow gamma rayradiation data to be collected at sufficient points around thecircumference of the wellbore for said image log to be prepared, whereinsaid image log is of an entire geologic unit surrounding the wellbore.5. The method of claim 1, wherein said logging tool body furtherincludes an outer sheath, and wherein said gamma ray radiation sensorsare positioned within said outer sheath.
 6. The method of claim 1,wherein said logging tool assembly further comprises a central corepositioned along said central longitudinal axis of said logging toolbody between said central longitudinal axis of said logging tool bodyand said sensors, said central core including a gamma ray shieldingmaterial.
 7. The method of claim 1, wherein said gamma ray radiationsensors are linearly arranged and spaced around said centrallongitudinal axis of said logging tool body in at least one row.
 8. Themethod of claim 7, wherein said gamma ray radiation sensors are linearlyarranged and equally spaced around said central longitudinal axis ofsaid logging tool body in two rows with each row having multiplesensors.
 9. The method of claim 8, wherein said gamma ray radiationsensors in one of said rows are vertically aligned to the sensors in theother row.
 10. The method of claim 8, wherein said gamma ray radiationsensors in one of said rows are vertically offset from the sensors inthe other row.
 11. The method of claim 1, wherein said gamma rayradiation sensors are vertically staggered and spaced around saidcentral longitudinal axis of said logging tool body in at least one row.12. The method of claim 11, wherein said gamma ray radiation sensors arevertically staggered and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensors.
 13. The method of claim 1, wherein said gamma ray radiationsensors are helically arranged and spaced around said centrallongitudinal axis of said logging tool body in at least one row.
 14. Themethod of claim 13, wherein said gamma ray radiation sensors arehelically arranged and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensors and wherein each of said at least two rows is helical.
 15. Themethod of claim 1, wherein said logging tool assembly includes at leasttwo sets of gamma ray radiation sensors, wherein for each set, saidsensors are positioned relative to the other sensors in the set so as tocollect gamma ray radiation in an areal array of recorded points, andsaid gamma ray radiation sensors in each set are attached to saidlogging tool body and equally spaced around said central longitudinalaxis of said logging tool body, and wherein the sets are spaced fromeach other along said central longitudinal axis of said logging toolbody.
 16. The method of claim 1, wherein said logging tool assemblyincludes a first set and a second set of gamma ray radiation sensors,wherein for each set, said sensors are positioned relative to the othersensors in the set so as to collect gamma ray radiation in an arealarray of recorded points, and said gamma ray radiation sensors arehelically arranged and equally spaced around said central longitudinalaxis of said logging tool body in at least two rows in each set.
 17. Themethod of claim 16, wherein said gamma ray radiation sensors arehelically arranged to form a two-row right-handed helical arrangementaround said central longitudinal axis of said logging tool body in eachset.
 18. The method of claim 16, wherein said gamma ray radiationsensors in said first set are helically arranged to form a right-handedhelical arrangement around said central longitudinal axis of saidlogging tool body, and said gamma ray radiation sensors in said secondset are helically arranged to form a left-handed helical arrangementaround said central longitudinal axis of said logging tool body.
 19. Themethod of claim 1, wherein said logging tool assembly is moved throughat least a portion of the wellbore at a logging speed of no greater than750 feet per hour.
 20. The method of claim 1, wherein said correctedgamma ray radiation data is vertically sampled at a vertical distancesampling rate of once every vertical distance sampling interval, whereinsaid vertical distance sampling interval is no greater than six inches.21. The method of claim 1, wherein said cased well is an inactive orpermanently abandoned well.
 22. The method of claim 21, wherein saidcased well is an inactive or permanently abandoned well for which thereis no prior well image log.
 23. A method of creating a well image log ofa cased well, comprising: providing a passive cased well image loggingtool assembly, said logging tool assembly including: an elongatedlogging tool body having a central longitudinal axis; a plurality ofsensor assemblies attached to said logging tool body and equally spacedaround said central longitudinal axis of said logging tool body, eachsensor assembly being positioned within said logging tool body andincluding: a housing; a gamma ray radiation sensor contained by saidhousing, said sensor being capable of continuously collecting gamma rayradiation data from one or more geologic units surrounding or adjacentto the wellbore as said logging tool assembly is moved through thewellbore, wherein said gamma ray radiation sensor is a gamma rayradiation scintillation crystal; and a photomultiplier tube associatedwith said sensor, said photomultiplier tube having a centrallongitudinal axis, a first end, and a second end, wherein said sensor isattached to one end of said corresponding photomultiplier tube; and atleast one spatial positioning device attached to said logging tool bodythat is capable of continuously collecting sensor position datareflecting the xyz spatial position of said sensors in the wellborerelative to the wellbore and the Earth as said logging tool assembly ismoved through the wellbore; and moving said logging tool assemblythrough at least a portion of the wellbore; as said logging toolassembly is being moved through the wellbore, using said sensors tocontinuously collect gamma ray radiation data that is emitted by thegeologic unit(s); as said logging tool assembly is being moved throughthe wellbore, using said spatial positioning device to continuouslycollect sensor position data reflecting the xyz spatial position of saidsensors within the wellbore relative to the wellbore and the Earth;using said collected sensor position data to correct said collectedgamma ray radiation data; vertically sampling said corrected gamma rayradiation data, wherein said sensor assemblies are positioned relativeto each other so that said sampling said corrected gamma ray radiationdata produces, at each of a plurality of sampling intervals, an areameasurement comprising recorded points and calculated points, whereinsaid calculated points are produced from measurements of gamma radiationcollected at two or more of said recorded points; and preparing a wellimage log based on said sampled gamma ray radiation data.
 24. The methodof claim 23, wherein both said sensor and said photomultiplier tube arecontained by said housing.
 25. The method of claim 23, wherein saidlogging tool body further includes an outer sheath, and wherein saidsensor assemblies are positioned within said outer sheath.
 26. Themethod of claim 25, wherein said logging tool assembly further comprisesa central core positioned within said outer sheath along said centrallongitudinal axis of said logging tool body between said centrallongitudinal axis of said logging tool body and said sensor assemblies,said central core including a gamma ray shielding material.
 27. Themethod of claim 23, wherein said sensor assemblies are linearly arrangedand equally spaced around said central longitudinal axis of said loggingtool body in at least one row.
 28. The method of claim 27, wherein saidsensor assemblies are linearly arranged and equally spaced around saidcentral longitudinal axis of said logging tool body in two rows witheach row having multiple sensor assemblies.
 29. The method of claim 23,wherein said sensor assemblies are vertically staggered around saidcentral longitudinal axis of said logging tool body in at least one row.30. The method of claim 23, wherein said sensor assemblies arevertically staggered and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensor assemblies.
 31. The method of claim 23, wherein said sensorassemblies are helically arranged around said central longitudinal axisof said logging tool body in at least one row.
 32. The method of claim31, wherein said sensor assemblies are helically arranged and equallyspaced around said central longitudinal axis of said logging tool bodyin two rows with each row having multiple sensor assemblies and whereineach of said at least two rows is helical.
 33. A passive cased wellimage logging tool assembly for use in a cased well, comprising: anelongated logging tool body having a central longitudinal axis; aplurality of gamma ray radiation sensors attached to said logging toolbody and spaced around said central longitudinal axis of said loggingtool body, each gamma ray radiation sensor being capable of continuouslycollecting gamma ray radiation data from one or more geologic unitssurrounding or adjacent to the wellbore as said logging tool assembly ismoved through the wellbore; at least one spatial positioning deviceattached to said logging tool body that is capable of continuouslycollecting sensor position data reflecting the xyz spatial position ofsaid gamma ray radiation sensors in the wellbore relative to thewellbore and the Earth as said logging tool assembly is moved throughthe wellbore; and a signal processing unit configured to sample gammaray radiation data, wherein said gamma ray radiation sensors arepositioned relative to each other so that said sampling produces, ateach of a plurality of sampling intervals, an area measurementcomprising recorded points and calculated points, wherein saidcalculated points are produced from measurements of gamma radiationcollected at two or more of said recorded points.
 34. The tool assemblyof claim 33, wherein said gamma ray radiation sensors are attached tosaid logging tool body and equally spaced around said centrallongitudinal axis of said logging tool body.
 35. The tool assembly ofclaim 33, wherein each of said sensors is a scintillation crystal. 36.The method of claim 33, wherein said logging tool body further includesan outer sheath, and wherein said gamma ray radiation sensors arepositioned within said outer sheath.
 37. The method of claim 33, whereinsaid logging tool assembly further comprises a central core positionedalong said central longitudinal axis of said logging tool body betweensaid central longitudinal axis of said logging tool body and saidsensors, said central core including a gamma ray shielding material. 38.The tool assembly of claim 33, wherein said gamma ray radiation sensorsare linearly arranged and equally spaced around said centrallongitudinal axis of said logging tool body in at least one row.
 39. Thetool assembly of claim 38, wherein said gamma ray radiation sensors arelinearly arranged and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensors.
 40. The tool assembly of claim 38, wherein said gamma rayradiation sensors in one of said rows are vertically aligned to thesensors in the other row.
 41. The tool assembly of claim 38, whereinsaid gamma ray radiation sensors in one of said rows are verticallyoffset from the sensors in the other row.
 42. The tool assembly of claim33, wherein said gamma ray radiation sensors are vertically staggeredand equally spaced around said central longitudinal axis of said loggingtool body in at least one row.
 43. The tool assembly of claim 42,wherein said gamma ray radiation sensors are vertically staggered andequally spaced around said central longitudinal axis of said loggingtool body in two rows with each row having multiple sensors.
 44. Thetool assembly of claim 33, wherein said gamma ray radiation sensors arehelically arranged and equally spaced around said central longitudinalaxis of said logging tool body in at least one row.
 45. The toolassembly of claim 44, wherein said gamma ray radiation sensors arehelically arranged and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensors and wherein each of said at least two rows is helical.
 46. Apassive cased well image logging tool assembly for use in a cased well,comprising: an elongated logging tool body having a central longitudinalaxis; a plurality of sensor assemblies attached to said logging toolbody and equally spaced around said central longitudinal axis of saidlogging tool body, each sensor assembly being positioned within saidlogging tool body and including: a housing; a gamma ray radiation sensorcontained by said housing, said sensor being capable of continuouslycollecting gamma ray radiation data from one or more geologic unitssurrounding or adjacent to the wellbore as said logging tool assembly ismoved through the wellbore, wherein said gamma ray radiation sensor is agamma ray radiation scintillation crystal; and a photomultiplier tubeassociated with said sensor, said photomultiplier tube having a centrallongitudinal axis, a first end, and a second end, wherein said sensor isattached to one end of said corresponding photomultiplier tube; at leastone spatial positioning device attached to said logging tool body thatis capable of continuously collecting sensor position data reflectingthe xyz spatial position of said gamma ray radiation sensors in thewellbore relative to the wellbore and the Earth as said logging toolassembly is moved through the wellbore; and a signal processing unitconfigured to sample gamma ray radiation data, wherein said sensorassemblies are positioned relative to each other so that said sampling,produces at each of a plurality of sampling intervals, an areameasurement comprising recorded points and calculated points, whereinsaid calculated points are produced from measurements of gamma radiationcollected at two or more of said recorded points.
 47. The tool assemblyof claim 46, wherein said logging tool body further includes an outersheath, and wherein said sensor assemblies are positioned within saidouter sheath.
 48. The tool assembly of claim 47, wherein said loggingtool assembly further comprises a central core positioned within saidouter sheath along said central longitudinal axis of said logging toolbody between said central longitudinal axis of said logging tool bodyand said sensor assemblies, said central core including a gamma rayshielding material.
 49. The tool assembly of claim 48, wherein saidsensor assemblies are linearly arranged and equally spaced around saidcentral longitudinal axis of said logging tool body in at least one row.50. The tool assembly of claim 49, wherein sensor assemblies arelinearly arranged and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensor assemblies.
 51. The tool assembly of claim 48, wherein sensorassemblies are vertically staggered and equally spaced around saidcentral longitudinal axis of said logging tool body in at least one row.52. The tool assembly of claim 51, wherein said sensor assemblies arevertically staggered and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensor assemblies.
 53. The tool assembly of claim 48, wherein saidsensor assemblies are helically arranged and equally spaced around saidcentral longitudinal axis of said logging tool body in at least one row.54. The tool assembly of claim 53, wherein said sensor assemblies arehelically arranged and equally spaced around said central longitudinalaxis of said logging tool body in two rows with each row having multiplesensors and wherein each of said at least two rows is helical.